UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K

(Mark One)
[X]  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
þANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 20092011
OR
[ ]  
oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from __________________ to ___________________

Commission
Commission
File Number
Registrant; State of Incorporation;
I.R.S. Employer
File Number
Address; and Telephone Number
I.R.S. Employer
Identification No.
   
333-21011FIRSTENERGY CORP.34-1843785
 (An Ohio Corporation) 
 76 South Main Street 
 Akron, OH 44308 
 Telephone (800)736-3402 
   
333-145140-01000-53742FIRSTENERGY 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 COMPANY34-0437786
 (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 


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

Registrant Title of Each Class 
Name of Each Exchange
Registrant
Title of Each Class
on Which Registered
     
FirstEnergy Corp. Common Stock, $0.10 par value New York Stock Exchange

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

Registrant Title of Each Class
   
Registrant
FirstEnergy Solutions Corp.		 
Title of Each Class
Common Stock, no par value per share
   
Ohio Edison Company Common Stock, no par value per share
   
The Cleveland Electric Illuminating Company Common Stock, no par value per share
   
The Toledo Edison Company Common Stock, $5.00 par value per share
   
Jersey Central Power & Light Company Common Stock, $10.00 par value per share
   
Metropolitan Edison Company Common Stock, no par value per share
   
Pennsylvania Electric Company Common Stock, $20.00 par value per share
FirstEnergy Solutions Corp.Common Stock, no par value per share


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

Yes (X)þ No (  )o
FirstEnergy Corp.
Yes (  )o No (X)þ
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 if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes (  )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 FirstEnergy Solutions Corp.

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

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

(X)
Yes o No þ
FirstEnergy Corp.,
Yes þ 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 definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting 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
(  )
N/A

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

Yes (  )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

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and ask price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter.

FirstEnergy Corp., $11,812,372,021$18,414,746,649 as of June 30, 2009;2011; and for all other registrants, none.

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

OUTSTANDING
CLASS 
OUTSTANDING
AS OF JANUARY 31, 20102012
FirstEnergy Corp., $.10$0.10 par value 418,216,437304,835,407
FirstEnergy Solutions Corp., no par value 7
Ohio Edison Company, no par value 60
The Cleveland Electric Illuminating Company, no par value 67,930,743
The Toledo Edison Company, $5 par value 29,402,054
Jersey Central Power & Light Company, $10 par value 13,628,447
Metropolitan Edison Company, no par value 740,905859,500
Pennsylvania Electric Company, $20 par value 4,427,577
FirstEnergy Corp. is the sole holder of FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company, and Pennsylvania Electric Company common stock.

Documents incorporated by reference (to the extent indicated herein):

DOCUMENT 
PART OF FORM 10-K INTO WHICH
DOCUMENT
DOCUMENT IS INCORPORATED
FirstEnergy Corp. Annual Report to Stockholders for
the fiscal year ended December 31, 2009Part II
   
Proxy Statement for 20102012 Annual Meeting of Stockholders
to be held May 18, 201015, 2012 PartParts II and III

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

OMISSION OF CERTAIN INFORMATION

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




Forward-Looking Statements: This Form 10-K 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’smanagement'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 speed and nature of increased competition in the electric utility industry.
·The impact of the regulatory process on the pending matters in Ohio, Pennsylvania and New Jersey.
The impact of the regulatory process on the pending matters before FERC and in the various states in which we do business including, but not limited to, matters related to rates.
·Business and regulatory impacts from ATSI’s realignment into PJM.
The status of the PATH project in light of PJM's direction to suspend work on the project pending review of its planning process, its re-evaluation of the need for the project and the uncertainty of the timing and amounts of any related capital expenditures.
·Economic or weather conditions affecting future sales and margins.
Business and regulatory impacts from ATSI's realignment into PJM.
·Changes in markets for energy services.
Economic or weather conditions affecting future sales and margins.
·Changing energy and commodity market prices and availability.
Changes in markets for energy services.
·Replacement power costs being higher than anticipated or inadequately hedged.
Changing energy and commodity market prices and availability.
·The continued ability of FirstEnergy’s regulated utilities to collect transition and other charges or to recover increased transmissionFinancial derivative reforms that could increase our liquidity needs and collateral costs.
·Operation and maintenance costs being higher than anticipated.
The continued ability of FirstEnergy's regulated utilities to collect transition and other costs.
·Other legislative and regulatory changes, and revised environmental requirements, including possible GHG emission regulations.
Operation and maintenance costs being higher than anticipated.
·The potential impacts of the U.S. Court of Appeals’ July 11, 2008 decision requiring revisions to the CAIR rules and the scope of any laws, rules or regulations that may ultimately take their place.
Other legislative and regulatory changes, and revised environmental requirements, including possible GHG emission, water intake and coal combustion residual regulations, the potential impacts of any laws, rules or regulations that ultimately replace CAIR, including CSAPR which was stayed by the courts on December 30, 2011, and the effects of the EPA's MATS 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.
The uncertainty of the timing and amounts of the capital expenditures that may arise in connection with any litigation including NSR litigation or potential regulatory initiatives or rulemakings (including that such expenditures could result in our decision to shut down or idle certain generating units).
·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.
The uncertainty associated with the company's plan to retire its older unscrubbed regulated and competitive fossil units, including the impact on vendor commitments and PJM's review of the company's plans.
·Ultimate resolution of Met-Ed’s and Penelec’s TSC filings with the PPUC.
Adverse regulatory or legal decisions and outcomes with respect to our nuclear operations (including, but not limited to the revocation or non-renewal of necessary licenses, approvals or operating permits by the NRC including as a result of the incident at Japan's Fukushima Daiichi Nuclear Plant).
·The continuing availability of generating units and their ability to operate at or near full capacity.
Issues that could result from our continuing investigation and analysis of the indications of cracking in the plant shield building at Davis-Besse.
·The ability to comply with applicable state and federal reliability standards and energy efficiency mandates.
Adverse legal decisions and outcomes related to Met-Ed's and Penelec's ability to recover certain transmission costs through their transmission service charge riders.
·The ability to accomplish or realize anticipated benefits from strategic goals (including employee workforce initiatives).
The continuing availability of generating units and changes in their ability to operate at or near full capacity.
·The ability to improve electric commodity margins and to experience growth in the distribution business.
Replacement power costs being higher than anticipated or inadequately hedged.
·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 comply with applicable state and federal reliability standards and energy efficiency mandates.
·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 customers' demand for power, including but not limited to, changes resulting from the implementation of state and federal energy efficiency mandates.
·Changes in general economic conditions affecting the registrants.
The ability to accomplish or realize anticipated benefits from strategic goals.
·The state of the capital and credit markets affecting the registrants.
FirstEnergy's ability to improve electric commodity margins and the impact of, among other factors, the increased cost of fuel and fuel transportation on such margins.
·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 ability to experience growth in the distribution business.
·The continuing decline of the national and regional economy and its impact on the registrants’ major industrial and commercial customers.
The changing market conditions that could affect the value of assets held in FirstEnergy's NDTs, pension trusts and other trust funds, and cause FirstEnergy and its subsidiaries to make additional contributions sooner, or in amounts that are larger than currently anticipated.
·Issues concerning the soundness of financial institutions and counterparties with which the registrants do business.
The impact of changes to material accounting policies.
·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 our 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 ability to access the public securities and other capital and credit markets in accordance with FirstEnergy's financing plan, the cost of such capital and overall condition of the capital and credit markets affecting FirstEnergy and its subsidiaries.
·The risks and other factors discussed from time to time in the registrants’ SEC filings,Changes in general economic conditions affecting FirstEnergy and its subsidiaries.
Interest rates and any actions taken by credit rating agencies that could negatively affect FirstEnergy's and its subsidiaries' 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 uncertainty of the national and regional economy and its impact on major industrial and commercial customers of FirstEnergy and its subsidiaries.
Issues concerning the soundness of financial institutions and counterparties with which FirstEnergy and its subsidiaries do business.
Issues arising from the completed merger of FirstEnergy and AE and the ongoing coordination of their combined operations including FirstEnergy's ability to maintain relationships with customers, employees and suppliers, as well as the ability to continue to successfully integrate the businesses and realize cost savings and other synergies.
The risks and other factors discussed from time to time in FirstEnergy's and its applicable subsidiaries' SEC filings, and



other similar factors.

Dividends declared from time to time on FE's common stock during any annual period may in the aggregate vary from the indicated amount due to circumstances considered by FE's Board of Directors at the time of the actual declarations. A security rating is not a recommendation to buy or hold securities and is subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.
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’FirstEnergy's 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, except as required by law, any forward-looking statements contained herein as a result of new information, future events or otherwise.




GLOSSARY OF TERMS

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

AEAllegheny Energy, Inc., a Maryland utility holding company that merged with a subsidiary of FirstEnergy on February 25, 2011
AESCAllegheny Energy Service Corporation, a subsidiary of AE
AE SupplyAllegheny Energy Supply Company, LLC, an unregulated generation subsidiary of AE
AETAllegheny Energy Transmission, LLC, a subsidiary of AE, which is the parent of TrAIL and has a joint venture in PATH.
AGCAllegheny Generating Company, a generation subsidiary of AE
AlleghenyAllegheny Energy, Inc., together with its consolidated subsidiaries
ATSIAmerican Transmission Systems, Incorporated, which owns and operates transmission facilities
Buchanan EnergyBuchanan Energy Company of Virginia, LLC, a subsidiary of AE Supply
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
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 RegistrantsFirstEnergy, OE, 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:
AEPAmerican Electric Illuminating Company, an Ohio electric utility operating subsidiary
CenteriorCenterior Energy Corp., former parent of CEI and TE, which merged with OE to form FirstEnergy in 1997
FEFirstEnergy Corp., a public utility holding company
FENOCFirstEnergy Nuclear Operating Company, which operates nuclear generating facilities
FESFirstEnergy Solutions Corp., which provides energy-related products and services
FESCFirstEnergy Service Company, which provides legal, financial and other corporate support services
FEVFirstEnergy Ventures Corp., which invests in certain unregulated enterprises and business ventures
FGCOFirstEnergy Generation Corp., a subsidiary of FES, which owns and operates non-nuclear generating facilities
FirstEnergyFirstEnergy Corp., together with its consolidated subsidiaries
Global HoldingGlobal Mining Holding Company, LLC, a joint venture between FEV, WMB Marketing Ventures, LLC and Gunvor Group, Ltd. that owns Global Rail and Signal Peak
Global RailA joint venture between FEV, WMB Marketing Ventures, LLC and Gunvor Group, Ltd. that owns coal transportation operations near Roundup, Montana
GPUGPU, Inc., former parent of JCP&L, Met-Ed and Penelec, that merged with FirstEnergy on November 7, 2001
JCP&LJersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
Merger SubElement Merger Sub, Inc., a Maryland corporation and a wholly owned subsidiary of FirstEnergy
Met-EdMetropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
MPMonongahela Power Company, a West Virginia electric utility operating subsidiary of AE
NGCFirstEnergy Nuclear Generation Corp., a subsidiary of FES, which owns nuclear generating facilities
OEOhio Edison Company, an Ohio electric utility operating subsidiary
Ohio CompaniesCEI, OE and TE
PATHPotomac-Appalachian Transmission Highline, LLC, a joint venture between Allegheny and a subsidiary of AEP
PATH-AlleghenyPATH Allegheny Transmission Company, LLC
PATH-VAPATH Allegheny Virginia Transmission Corporation
PEThe Potomac Edison Company, a Maryland electric utility operating subsidiary of AE
PenelecPennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
PennPennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
Pennsylvania CompaniesMet-Ed, Penelec, Penn and WP
PNBVPNBV Capital Trust, a special purpose entity created by OE in 1996
ShippingportShippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
Signal PeakA joint venture between FEV, WMB Marketing Ventures, LLC and Gunvor Group, Ltd. that owns mining operations near Roundup, Montana
TEThe Toledo Edison Company, an Ohio electric utility operating subsidiary
TrAILTrans-Allegheny Interstate Line Company, a subsidiary of AET
UtilitiesOE, CEI, TE, Penn, JCP&L, Met-Ed, Penelec, MP, PE and WP
Utility RegistrantsOE, CEI, TE, JCP&L, Met-Ed and Penelec
WPWest Penn Power Company, a Pennsylvania electric utility operating subsidiary of AE
The following abbreviations and acronyms are used to identify frequently used terms in this report:
ALJAdministrative Law Judge
Anker WVAnker West Virginia Mining Company, Inc.
Anker CoalAnker Coal Group, Inc.
ALJAdministrative Law Judge
AMP-OhioAmerican Municipal Power-Ohio, Inc.
AOCLAccumulated Other Comprehensive Loss
AQCAir Quality Control
AROAsset Retirement Obligation
BGSBasic Generation Service
CAAClean Air Act
CAIRClean Air Interstate Rule
CAMRClean Air Mercury Rule
CAVRClean Air Visibility Rule
CBPCompetitive Bid Process
CMECCapacity market Evolution Committee


i


CO2
Carbon dioxide
CTCCompetitive Transition Charge
DOEUnited States Department of Energy
DOJUnited States Department of Justice
DCPDDeferred Compensation Plan for Outside Directors
DPADepartment of the Public Advocate, Division of Rate Counsel (New Jersey)
ECAREast Central Area Reliability Coordination Agreement
GLOSSARY OF TERMS, Continued

AOCIAccumulated Other Comprehensive Income
AEPAmerican Electric Power Company, Inc.
AMTAlternative Minimum Tax
AQCAir Quality Control
AROAsset Retirement Obligation
AREPAAlternative and Renewable Energy Portfolio Act
ARRAuction Revenue Right
ASLBAtomic Safety and Licensing Board
BGSBasic Generation Service
BMPBruce Mansfield Plant
CAAClean Air Act
CALConfirmatory Action Letter
CAIRClean Air Interstate Rule
CAMRClean Air Mercury Rule
CATRClean Air Transport Rule
CBPCompetitive Bid Process
CCBCoal Combustion By-products
CDWRCalifornia Department of Water Resources
CERCLAComprehensive Environmental Response, Compensation, and Liability Act
CFLCompact Florescent Light bulb
CFTCCommodity Futures Trading Commission
CO2
Carbon Dioxide
CSAPRCross-State Air Pollution Rule
CTCCompetitive Transition Charge
CWAClean Water Act
CWIPConstruction Work in Progress
DCPDDeferred Compensation Plan for Outside Directors
DCRDelivery Capital Recovery Rider
DOEUnited States Department of Energy
DOJUnited States Department of Justice
DSPDefault Service Plan
DukeDuke Energy Corporation
EDCElectric Distribution Company
EDCPExecutive Deferred Compensation Plan
EE&CEnergy Efficiency and Conservation
EGSElectric Generation Supplier
EMPEnergy Master Plan
ENECExpanded Net Energy Cost
EPAUnited States Environmental Protection Agency
EPACTEnergy Policy Act of 2005
EPRIElectric Power Research Institute
EROElectric Reliability Organization
ESOPEmployee Stock Ownership Plan
ESPElectric Security Plan
FASBFinancial Accounting Standards Board
FERCFederal Energy Regulatory Commission
FitchFitch Ratings
FMBFirst Mortgage Bond
FPAFederal Power Act
FTRFinancial Transmission Right
GAAPAccounting Principles Generally Accepted in the United States
Generation Asset TransfersIntra-system generation asset transfers from the Ohio Companies and Penn to FGCO and NGC


i

ii


GLOSSARY OF TERMS, Cont'd.Continued

GHGGreenhouse Gases
ICGInternational Coal Group inc.
ILPIntegrated License Application Process
IRSInternal Revenue Service
kVKilovolt
KWHKilowatt-hour
LBRLittle Blue Run
LiDARLight Detection and Ranging
LOCLetter of Credit
LSELoad Serving Entity
LTIPLong-Term Incentive Plan
MATSMercury and Air Toxics Standards
MDEMaryland Department of the Environment
MDPSCMaryland Public Service Commission
Mine ActFederal Mine Safety and Health Act of 1977
MISOMidwest Independent Transmission System Operator, Inc.
MissionMission Energy Westside, Inc.
Moody’sMoody’s Investors Service, Inc.
MSHAMine Safety and Health Administration
MTEPMISO Regional Transmission Expansion Plan
MVPMulti-value Project
MWMegawatt
MWHMegawatt-hour
NAAQSNational Ambient Air Quality Standards
NDTNuclear Decommissioning Trust
NEILNuclear Electric Insurance Limited
NEPANational Environmental Policy Act
NERCNorth American Electric Reliability Corporation
NJBPUNew Jersey Board of Public Utilities
NNSRNon-Attainment New Source Review
NOVNotice of Violation
NOxNitrogen Oxide
NPDESNational Pollutant Discharge Elimination System
NRCNuclear Regulatory Commission
NSRNew Source Review
NUGNon-Utility Generation
NYPSCNew York State Public Service Commission
NYSEGNew York State Electric and Gas
OCAOffice of Consumer Advocate (Pennsylvania)
OCIOther Comprehensive Income
OPEBOther Post-Employment Benefits
OSBAOffice of Small Business Advocate
OTCOver The Counter
OTTIOther Than Temporary Impairments
OVECOhio Valley Electric Corporation
PADPre-application Document
PA DEPPennsylvania Department of Environmental Protection
PCBPolychlorinated Biphenyl
PCRBPollution Control Revenue Bond
PJMPJM Interconnection L. L. C.
PMParticulate Matter


FERCFederaliii


GLOSSARY OF TERMS, Continued

POLRProvider of Last Resort
PPUCPennsylvania Public Utility Commission
PSAPower Supply Agreement
PSDPrevention of Significant Deterioration
PUCOPublic Utilities Commission of Ohio
PURPAPublic Utility Regulatory Policies Act of 1978
R&DResearch and Development
RECRenewable Energy Credit
RFC
ReliabilityFirst
RFPRequest for Proposal
RGGIRegional Greenhouse Gas Initiative
ROEReturn on Equity
RPMReliability Pricing Model
RPSRules Governing Alternative and Renewable Energy Portfolio Standard
RTEPRegional Transmission Expansion Plan
RTORegional Transmission Organization
S&PStandard & Poor’s Ratings Service
SB221Amended Substitute Senate Bill 221
SBCSocietal Benefits Charge
SECUnited States Securities and Exchange Commission
SIPState Implementation Plan(s) Under the Clean Air Act
SMIPSmart Meter Implementation Plan
SO2
Sulfur Dioxide
SOSStandard Offer Service
SRECSolar Renewable Energy Regulatory Commission
FMBFirst Mortgage Bond
FPAFederal Power Act
FRRFixed Resource Requirement
GAAPAccounting Principles Generally Accepted in the United States
GHGGreenhouse Gases
IBEWInternational Brotherhood of Electrical Workers
IFRSInternational Financial Reporting Standards
IRSInternal Revenue Service
JCARRJoint Committee on Agency Review
kVKilovolt
KWHKilowatt-hours
LEDLight-emitting Diode
LIBORLondon Interbank Offered Rate
LOCLetter of Credit
LTIPLong-Term Incentive Plan
MACTMaximum Achievable Control Technology
MISOMidwest Independent Transmission System Operator, Inc.
Moody'sMoody's Investors Service, Inc.
MROMarket Rate Offer
MWMegawatts
MWHMegawatt-hours
NAAQSNational Ambient Air Quality Standards
NEILNuclear Electric Insurance Limited
NERCNorth American Electric Reliability Corporation
NJBPUNew Jersey Board of Public Utilities
NNSRNon-Attainment New Source Review
NOPECNortheast Ohio Public Energy Council
NOVNotice of Violation
NOX
Nitrogen Oxide
NRCNuclear Regulatory Commission
NSRNew Source Review
NUGNon-Utility Generation
NUGCNon-Utility Generation Charge
OCCOhio Consumers’ Counsel
OCIOther Comprehensive Income
OPEBOther Post-Employment Benefits
OVECOhio Valley Electric Corporation
PCRBPollution Control Revenue Bond
PJMPJM Interconnection L. L. C.
PLR
Provider of Last Resort; an electric utility's obligation to provide generation service to customers
   whose alternative supplier fails to deliver service
PPUCPennsylvania Public Utility Commission
PSAPower Supply Agreement
PSDPrevention of Significant Deterioration
PUCOPublic Utilities Commission of Ohio
QSPEQualifying 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's Ratings Service
SB221Amended Substitute Senate Bill 221
SBCSocietal Benefits Charge
SECU.S. Securities and Exchange Commission
SECASeams Elimination Cost Adjustment
SIPState Implementation Plan(s) Under the Clean Air Act
SNCRSelective Non-Catalytic Reduction
SO2
Sulfur Dioxide
SRECsSolar Renewable Energy Credits
TBCTransition Bond Charge
ii
GLOSSARY OF TERMS, Cont'd.

TDSTotal Dissolved Solid
TMDLTotal Maximum Daily Load
TMI-2Three Mile Island Unit 2
TOTransmission Owner
TSCTransmission Service Charge
VEROVoluntary Enhanced Retirement Option
VIEVariable Interest Entity
VSCCVirginia State Corporation Commission
WVDEPWest Virginia Department of Environmental Protection
WVPSCPublic Service Commission of West Virginia







iv


iii
FORM 10-K TABLE OF CONTENTS

 Page
  
Glossary of Terms
i
Part I
Item 1. Business
1
The Company
1
Utility Regulation
3
State Regulation
3
Federal Regulation
3
Regulatory Accounting
3
Reliability Initiatives
4
Maryland Regulatory Matters
4
New Jersey Regulatory Matters
5
Ohio Regulatory Matters
6
Pennsylvania Regulatory Matters
7
West Virginia Regulatory Matters
9
FERC Matters
9
Capital Requirements
12
Nuclear Operating Licenses
15
Nuclear Regulation
15
Nuclear Insurance
16
Hydro Relicensing
17
Environmental Matters
17
Fuel Supply
23
System Demand
24
Supply Plan
24
Regional Reliability
24
Competition
25
Seasonality
25
Research and Development
25
Executive Officers
26
Employees
27
FirstEnergy Web Site
27
Item 1A. Risk Factors
27
Item 1B. Unresolved Staff Comments
39
Item 2. Properties
39
Item 3. Legal Proceedings
42
Item 4. Mine Safety Disclosures
42
Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
43
  
Glossary of Termsi-iii
Part I
Item 1.Business1-26
The Company1-2
Utility Regulation2-13
State Regulation2
Federal Regulation3
Regulatory Accounting3-4
Reliability Initiatives4
Ohio Regulatory Matters4-6
Pennsylvania Regulatory Matters6-8
New Jersey Regulatory Matters8-9
FERC Matters9-13
Capital Requirements13-15
Nuclear Operating Licenses15-16
Nuclear Regulation16
Nuclear Insurance16-17
Environmental Matters17-21
Fuel Supply21-22
System Demand22-23
Supply Plan23
Regional Reliability23
Competition23-24
Research and Development24
Executive Officers25
Employees26
FirstEnergy Web Site26
Item 1A.Risk Factors27-41
Item 1B.Unresolved Staff Comments41
Item 2.Properties41-43
Item 3.Legal Proceedings43
Item 4.Submission of Matters to a Vote of Security Holders43
Part II
Item 5.Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities43-44
Item 6.Selected Financial Data44-45
Item 7.Management’s Discussion and Analysis of Registrant and Subsidiaries45-130
FirstEnergy Corp.47-105
FirstEnergy Solutions Corp.106-110
Ohio Edison Company111-113
The Cleveland Electric Illuminating Company114-115
The Toledo Edison Company116-118
Jersey Central Power & Light Company119-122
Metropolitan Edison Company123-126
Pennsylvania Electric Company127-130
Item 7A.Quantitative and Qualitative Disclosures About Market Risk131
Item 8.Financial Statements and Supplementary Data132-186
Management  Reports132-139
Report of Independent Registered Public Accounting Firm.140-147


iv

v


TABLE OF CONTENTS (Cont'd)(Continued)

 Page
Item 6. Selected Financial Data
43
Item 7. Management’s Discussion and Analysis of Registrant and Subsidiaries
45
FirstEnergy Corp.
47
FirstEnergy Solutions Corp.
103
Ohio Edison Company
108
The Cleveland Electric Illuminating Company
111
The Toledo Edison Company
114
Jersey Central Power & Light Company
117
Metropolitan Edison Company
120
Pennsylvania Electric Company
124
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
128
Item 8. Financial Statements and Supplementary Data
129
Management Reports
129
Report of Independent Registered Public Accounting Firm
137
Financial Statements
FirstEnergy Corp.
Consolidated Statements of Income
145
Consolidated Statements of Comprehensive Income
146
Consolidated Balance Sheets
147
Consolidated Statements of Common Stockholders' Equity
148
Consolidated Statements of Cash Flows
149
FirstEnergy Solutions Corp.
Consolidated Statements of Income and Comprehensive Income
150
Consolidated Balance Sheets
151
Consolidated Statements of Common Stockholder's Equity
152
Consolidated Statements of Cash Flows
153
Ohio Edison Company
Consolidated Statements of Income and Comprehensive Income
154
Consolidated Balance Sheets
155
Consolidated Statements of Common Stockholder's Equity
156
Consolidated Statements of Cash Flows
157
The Cleveland Electric Illuminating Company
Consolidated Statements of Income and Comprehensive Income
158
Consolidated Balance Sheets
159
Consolidated Statements of Common Stockholder's Equity
160
Consolidated Statements of Cash Flows
161
The Toledo Edison Company
Consolidated Statements of Income and Comprehensive Income
162
Consolidated Balance Sheets
163


vi


Financial Statements
FirstEnergy Corp.
Consolidated Statements of Income148
Consolidated Balance Sheets149
Consolidated Statements of Common Stockholders  Equity150
Consolidated Statements of Cash Flows151
FirstEnergy Solutions Corp.
Consolidated Statements of Income152
Consolidated Balance Sheets153
Consolidated Statements of Capitalization154
Consolidated Statements of Common Stockholders  Equity155
Consolidated Statements of Cash Flows156
Ohio Edison Company
Consolidated Statements of Income157
Consolidated Balance Sheets158
Consolidated Statements of Capitalization159
Consolidated Statements of Common Stockholders  Equity160
Consolidated Statements of Cash Flows161
The Cleveland Electric Illuminating Company
Consolidated Statements of Income162
Consolidated Balance Sheets163
Consolidated Statements of Capitalization164
Consolidated Statements of Common Stockholders  Equity165
Consolidated Statements of Cash Flows166
The Toledo Edison Company
Consolidated Statements of Income167
Consolidated Balance Sheets168
Consolidated Statements of Capitalization169
Consolidated Statements of Common Stockholders  Equity170
Consolidated Statements of Cash Flows171
Jersey Central Power & Light Company
Consolidated Statements of Income172
Consolidated Balance Sheets173
Consolidated Statements of Capitalization174
Consolidated Statements of Common Stockholders  Equity175
Consolidated Statements of Cash Flows176
Metropolitan Edison Company
Consolidated Statements of Income177
Consolidated Balance Sheets178
Consolidated Statements of Capitalization179
Consolidated Statements of Common Stockholders  Equity180
Consolidated Statements of Cash Flows181
Pennsylvania Electric Company
Consolidated Statements of Income182
Consolidated Balance Sheets183
Consolidated Statements of Capitalization184
Consolidated Statements of Common Stockholders  Equity185
Consolidated Statements of Cash Flows186
v

TABLE OF CONTENTS (Cont'd)(Continued)

 Page
Consolidated Statements of Common Stockholder's Equity
164
Consolidated Statements of Cash Flows
165
Jersey Central Power & Light Company
Consolidated Statements of Income and Comprehensive Income
166
Consolidated Balance Sheets
167
Consolidated Statements of Common Stockholder's Equity
168
Consolidated Statements of Cash Flows
169
Metropolitan Edison Company
Consolidated Statements of Income and Comprehensive Income
170
Consolidated Balance Sheets
171
Consolidated Statements of Common Stockholder's Equity
172
Consolidated Statements of Cash Flows
173
Pennsylvania Electric Company
Consolidated Statements of Income and Comprehensive Income
174
Consolidated Balance Sheets
175
Consolidated Statements of Common Stockholder's Equity
176
Consolidated Statements of Cash Flows
177
Combined Notes to Consolidated Financial Statements
178
Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure
275
Item 9A. Controls and Procedures — FirstEnergy
275
Item 9B. Other Information
275
Part III
Item 10. Directors, Executive Officers and Corporate Governance
275
Item 11. Executive Compensation
275
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
275
Item 13. Certain Relationships and Related Transactions, and Director Independence
275
Item 14. Principal Accounting Fees and Services
275
Part IV
Item 15. Exhibits, Financial Statement Schedules
277



vii


PART I
Combined Notes to Consolidated Financial Statements187-254
Item 9.Changes In and Disagreements with Accountants on Accounting and Financial Disclosure255
Item 9A.Controls and Procedures - FirstEnergy255
Item 9A(T).Controls and Procedures – FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec255
Item 9B.Other Information255
Part III
Item 10.Directors, Executive Officers and Corporate Governance256
Item 11.Executive Compensation256
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
256
Item 13.Certain Relationships and Related Transactions, and Director Independence256
Item 14.Principal Accounting Fees and Services256
Part IV
Item 15.Exhibits, Financial Statement Schedules
Report of Independent Registered Public Accounting Firm on Financial Statement Schedule257-293
vi
PART I
ITEM 1.
BUSINESS

Proposed Merger with Allegheny Energy, Inc.

On February 10, 2010, FirstEnergy entered into an Agreement and Plan of Merger (Merger Agreement) with Element Merger Sub, Inc., a Maryland corporation and its wholly-owned subsidiary (Merger Sub) and Allegheny Energy, Inc., a Maryland corporation (Allegheny). Upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will merge with and into Allegheny with Allegheny continuing as the surviving corporation and a wholly-owned subsidiary of FirstEnergy.  Pursuant to the Merger Agreement, upon the closing of the merger, each issued and outstanding share of Allegheny 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. Completion of the merger is conditioned upon, among other things, shareholder approval of both companies 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 Maryland Public Service Commission, PPUC, the Virginia State Corporation Commission and the West Virginia Public Service Commission. FirstEnergy anticipates that the necessary approvals will be obtained within 12 to 14 months.  The Merger Agreement contains certain termination rights for both FirstEnergy and Allegheny, and further provides for the payment of fees and expenses upon termination under specified circumstances. Further information concerning the proposed merger will be included in a joint proxy statement/prospectus contained in the registration statement on Form S-4 to be filed by FirstEnergy with the SEC in connection with the merger. See Note 21 to the consolidated financial statements.
The Company

FirstEnergy Corp. was organized under the laws of the State of Ohio in 1996. FirstEnergy’s principal business is the holding, directly or indirectly, of all of the outstanding common stock of its eight principal electric utility operating subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), ATSI, JCP&L, Met-Ed, Penelec, AE and Penelec;its principal subsidiaries (AE Supply, AGC, MP, PE, WP, AET and its principal subsidiaries (TrAIL and PATH), and AESC), FES and its principal subsidiaries (FGCO and NGC), and FESC. AE merged with a subsidiary of its generatingFirstEnergy on February 25, 2011, with AE continuing as the surviving corporation and marketingbecoming a wholly owned subsidiary FES. FirstEnergy’s consolidated revenues are primarily derived from electric service provided by its utility operating subsidiaries and the revenues of its other principal subsidiary, FES.FirstEnergy. In addition, FirstEnergy holds all of the outstanding common stock of other direct subsidiaries including: FirstEnergy Properties, Inc., FEV, FENOC, FELHC, Inc., FirstEnergy Facilities Services Group, LLC, FirstEnergy Fiber Holdings Corp., GPU Power, Inc., GPU Nuclear, Inc., MARBEL Energy Corporation and FESC.
Subsidiaries
FirstEnergy’s revenues are primarily derived from electric service provided by its utility operating subsidiaries (OE, CEI, TE, Penn, ATSI, JCP&L, Met-Ed, Penelec, MP, PE, WP and TrAIL) and the sale of energy and related products and services by its unregulated competitive subsidiaries, FES and AE Supply.
The Utilities’ combined service areas encompass approximately 65,000 square miles in Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York. The areas they serve have a combined population of approximately 13.6 million.
OE was organized under the laws of the State of Ohio in 1930 and owns property and does business as an electric public utility in that state. OE engages in the distribution and sale of electric energy to communities in a 7,000 square mile area of central and northeastern Ohio. The area it serves has a population of approximately 2.3 million. OE complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PUCO.
OE owns all of Penn’s outstanding common stock. Penn was organized under the laws of the Commonwealth of Pennsylvania in 1930 and owns property and does business as an electric public utility in that state. Penn is also authorized to do business in the State of Ohio. Penn furnishes electric service to communities in 1,100 square miles of western Pennsylvania. The area it serves has a population of approximately 0.4 million. Penn complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PPUC.
CEI was organized under the laws of the State of Ohio in 1892 and does business as an electric public utility in that state. CEI engages in the distribution and sale of electric energy in an area of 1,600 square miles in northeastern Ohio. The area it serves has a population of approximately 1.7 million. CEI complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PUCO.
TE was organized under the laws of the State of Ohio in 1901 and does business as an electric public utility in that state. TE engages in the distribution and sale of electric energy in an area of 2,300 square miles in northwestern Ohio. The area it serves has a population of approximately 0.7 million. TE complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PUCO.
ATSI was organized under the laws of the State of Ohio in 1998. ATSI owns major, high-voltage transmission facilities, which consist of approximately 5,800 pole miles of transmission lines with nominal voltages of 345 kV, 138 kV and 69 kV. On June 1, 2011, ATSI transferred operational control of its transmission facilities from MISO to PJM (see FERC Matters for RTO Realignment). ATSI plans, operates, and maintains its transmission system in accordance with NERC reliability standards, and applicable regulatory requirements to ensure reliable service to customers. ATSI complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and applicable state regulatory authorities.
JCP&L was organized under the laws of the State of New Jersey in 1925 and owns property and does business as an electric public utility in that state. JCP&L provides transmission and distribution services in 3,200 square miles of northern, western and east central New Jersey. The area it serves has a population of approximately 2.7 million. JCP&L also has an ownership interest in a hydroelectric generating facility. JCP&L complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and the NJBPU.
Met-Ed was organized under the laws of the Commonwealth of Pennsylvania in 1922 and owns property and does business as an electric public utility in that state. Met-Ed provides transmission and distribution services in 3,300 square miles of eastern and south central Pennsylvania. The area it serves has a population of approximately 1.2 million. Met-Ed complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PPUC.
Penelec was organized under the laws of the Commonwealth of Pennsylvania in 1919 and owns property and does business as an electric public utility in that state. Penelec provides transmission and distribution services in 17,600 square miles of western, northern and south central Pennsylvania. The area it serves has a population of approximately 1.3 million. Penelec, as lessee of the property of its subsidiary, The Waverly Electric Light & Power Company, also serves customers in the Waverly, New York vicinity.


1


Penelec complies with the regulations, orders, policies and practices prescribed by the SEC, FERC, NYPSC and PPUC, as applicable.
PE was organized under the laws of the State of Maryland in 1923 and in the Commonwealth of Virginia in 1974. PE is authorized to do business in the Commonwealth of Virginia and the States of West Virginia and Maryland. PE owns property and does business as an electric public utility in those states. PE provides transmission and/or distribution services in 5,500 square miles area in portions of Maryland, Virginia and West Virginia. The area it serves has a population of approximately 0.9 million. PE complies with the regulations, orders, policies and practices prescribed by the SEC, FERC, MDPSC, VSCC, and WVPSC, as applicable.
MP was organized under the laws of the State of Ohio in 1924 and owns property and does business as an electric public utility in the state of West Virginia. MP provides transmission and distribution services in 13,000 square miles of northern West Virginia. The area it serves has a population of approximately 0.8 million. MP also owns generation assets. As of December 31, 2011, MP owned or contractually controlled 2,737 MWs of generation capacity that is supplied to its electric utility business. In addition, MP is contractually obligated to provide PE with the power that it needs to meet its load obligations in West Virginia. MP complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and WVPSC, as applicable.
WP was organized under the laws of the Commonwealth of Pennsylvania in 1916 and owns property and does business as an electric public utility in that state. WP provides transmission and distribution services in 10,400 square miles of southwestern, south-central and northern Pennsylvania. The area it serves has a population of approximately 1.6 million. WP complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PPUC, as applicable.
TrAIL was organized under the laws of the State of Maryland and the Commonwealth of Virginia in 2006. TrAIL was formed in connection with the management and financing of a new 500kV transmission line. On May 19, 2011, TrAIL completed the construction and energized the transmission line. The transmission line extends approximately 150 miles from southwestern Pennsylvania through West Virginia to a point of interconnection with Virginia Electric and Power Company, a subsidiary of Dominion Resources, in northern Virginia. TrAIL complies with the regulations, orders, policies and practices prescribed by the SEC, FERC, WVPSC, VSCC and PPUC, as applicable.
FES was organized under the laws of the State of Ohio in 1997. FES provides energy-related products and services to wholesale and retail customers in the MISO and PJM markets.customers. FES also owns and operates, through its subsidiary, FGCO, FirstEnergy’s fossil and hydroelectric generating facilities and owns, through its subsidiary, NGC, FirstEnergy’s nuclear generating facilities. FENOC, a separate subsidiary of FirstEnergy, organized under the laws of the State of Ohio in 1998, operates and maintains NGC’s nuclear generating facilities. FES purchases the entire output of the generation facilities owned by FGCO and NGC, as well as the output relating to leasehold interests of the Ohio CompaniesOE and TE in certain of those facilities that are subject to sale and leaseback arrangements with non-affiliates, pursuant to full output, cost-of-service PSAs.

AE Supply was organized under the laws of the State of Delaware in 1999. AE Supply provides energy-related products and services to wholesale and retail customers. AE Supply also owns and operates fossil and hydroelectric generating facilities and purchases and sells energy and energy-related commodities.
AGC was organized under the laws of the Commonwealth of Virginia in 1981. AGC is owned approximately 59% by AE Supply and approximately 41% by MP. AGC’s sole asset is a 40% undivided interest in the Bath County, Virginia pumped-storage hydroelectric generation facility and its connecting transmission facilities. AGC provides the generation capacity from this facility to AE Supply and MP.
Competitive and Regulated Generation
FirstEnergy’s generating portfolio includes 13,97022,810 MW of diversified capacity (FES – 13,770(Competitive — 19,874 MW and JCP&L – 200Regulated — 2,936 MW), including 3,349 MW (Competitive - 2,689 MW and Regulated - 660 MW) of capacity that is planned to be retired by September 1, 2012, subject to review of reliability impacts by PJM (See Part I, Item 2. Properties). Within FES’Of the generation asset portfolio, approximately 7,46914,678 MW or 54.2%(64.4%), consistsconsist of coal-fired capacity; 3,991 MW or 29.0%, consists(17.5%) consist of nuclear capacity; 1,5991,832 MW or 11.6%, consists(8.0%) consist of hydroelectric capacity; 1,745 MW (7.7%) consist of oil and natural gas peaking units; 451376 MW or 3.3%, consists(1.6%) consist of hydroelectric capacity;wind facilities; and 260188 MW or 1.9%, consists(0.8%) consist of capacity from FGCO’s current 11.5% entitlementFGCO's 4.85% and AE's 3.5% entitlements to the generation output owned by OVEC. All units are located within PJM and sell electric energy, capacity and other products into the OVEC. FirstEnergy’s nuclear and non-nuclearwholesale markets that are operated by PJM.
Within the Competitive portfolio, 12,368 MW consist of FES' facilities that are operated by FENOC and FGCO respectively, and,(including entitlements to OVEC), except for portions of certain facilities that are subject to the sale and leaseback arrangements with non-affiliates referred to above for which the corresponding output is available to FES through power sale agreements, and are all owned directly by NGC and FGCO, respectively. The FES7,506 MW consist of AE Supply's facilities, including 660 MW from AGC's Bath County, Virginia hydroelectric facility that AE Supply partially owns. FES' generating assetsfacilities are concentrated primarily in Ohio plus the bordering regions ofand Pennsylvania and Michigan. All FES unitsAE Supply's primarily in Pennsylvania, West Virginia and Maryland.
Within the Regulated portfolio, 200 MW consist of JCP&L's 50% ownership interest in the Yards Creek hydroelectric facility in New Jersey; 2,725 MW consist of MP's facilities, including 450 MW from AGC's Bath County, Virginia hydroelectric facility that MP partially owns. MP's facilities are dedicatedconcentrated primarily in West Virginia. 11 MW consist of AE's 3.5% entitlement to MISO except the Beaver Valley Power Station, which is designated as a PJM resource. Additionally, see FERC Matters for RTO Consolidation.OVEC's generation output.


2


FES, FGCO, NGC, AE Supply and NGCAGC comply with the regulations, orders, policies and practices prescribed by the SEC and the FERC. In addition, NGC and FENOC comply with the regulations, orders, policies and practices prescribed by the NRC.

The Utilities’ combined service areas encompass approximately 36,100 square miles in Ohio, New JerseyFESC and Pennsylvania. The areas they serve have a combined population of approximately 11.3 million.

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

1
OE owns all of Penn’s outstanding common stock. Penn was organized under the laws of the Commonwealth of Pennsylvania in 1930 and owns property and does business as an electric public utility in that state. Penn is also authorized to do business in the State of Ohio (see Item 2 – Properties). Penn furnishes electric service to communities in 1,100 square miles of western Pennsylvania. The area it serves has a population of approximately 0.4 million. Penn complies with the regulations, orders, policies and practices prescribed by the FERC and PPUC.

CEI was organized under the laws of the State of Ohio in 1892 and does business as an electric public utility in that state. CEI engages in the distribution and sale of electric energy in an area of approximately 1,600 square miles in northeastern Ohio. The area it serves has a population of approximately 1.8 million. CEI complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PUCO.

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

ATSI was organized under the laws of the State of Ohio in 1998. ATSI owns transmission assets that were formerly owned by the Ohio Companies and Penn. ATSI owns major, high-voltage transmission facilities, which consist of approximately 5,821 pole miles of transmission lines with nominal voltages of 345 kV, 138 kV and 69 kV. Effective October 1, 2003, ATSI transferred operational control of its transmission facilities to MISO. With its affiliation with MISO, ATSI plans, operates, and maintains its transmission system in accordance with NERC reliability standards, and applicable regulatory agencies to ensure reliable service to customers. Additionally, see FERC Matters for RTO Consolidation.

JCP&L was organized under the laws of the State of New Jersey in 1925 and owns property and does business as an electric public utility in that state. JCP&L provides transmission and distribution services in 3,200 square miles of northern, western and east central New Jersey. The area it serves has a population of approximately 2.6 million. JCP&L complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and the NJBPU.

Met-Ed was organized under the laws of the Commonwealth of Pennsylvania in 1922 and owns property and does business as an electric public utility in that state. Met-Ed provides transmission and distribution services in 3,300 square miles of eastern and south central Pennsylvania. The area it serves has a population of approximately 1.3 million. Met-Ed complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PPUC.

Penelec was organized under the laws of the Commonwealth of Pennsylvania in 1919 and owns property and does business as an electric public utility in that state. Penelec provides transmission and distribution services in 17,600 square miles of western, northern and south central Pennsylvania. The area it serves has a population of approximately 1.6 million. Penelec, as lessee of the property of its subsidiary, The Waverly Electric Light & Power Company, also serves customers in Waverly, New York and its vicinity. Penelec complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PPUC.

FESC providesAESC provide legal, financial and other corporate support services to affiliated FirstEnergy companies.

Reference is made to Note 16,19, Segment Information, of the Combined Notes to the Consolidated Financial Statements contained in Item 8 for information regarding FirstEnergy'sFirstEnergy’s reportable segments.segments, which information is incorporated herein by reference.

Utility Regulation

State Regulation

Each of the Utilities’ retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the statestates in which each company operates –— in Maryland by the MDPSC, in Ohio by the PUCO, in New Jersey by the NJBPU, and in Pennsylvania by the PPUC.PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE in Virginia are subject to certain regulations of the VSCC. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility.

As a competitive retail electric supplier serving retail customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland, Michigan,FES and Illinois, FES isAE Supply are subject to state laws applicable to competitive electric suppliers in those states, including affiliate codes of conduct that apply to FES, AE Supply and its public utility affiliates. In addition, if FES, AE Supply or any of its subsidiaries were to engage in the construction of significant new generation facilities, they would also be subject to state siting authority.

2
Federal Regulation

With respect to their wholesale and interstate electric operations and rates, the Utilities, AE Supply, ATSI, AGC, FES, FGCO, NGC, PATH and NGCTrAIL are subject to regulation by the FERC. Under the FPA, the FERC regulates rates for interstate sales at wholesale, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects. The FERC regulations require ATSI, Met-Ed, JCP&L, Met-Ed, MP, PATH, PE, Penelec, WP and PenelecTrAIL to provide open access transmission service at FERC-approved rates, terms and conditions. TransmissionThrough May 31, 2011, transmission service over ATSI’s facilities iswas provided by MISO under its open access transmission tariff,tariff. For JCP&L, Met-Ed, MP, PATH, PE, Penelec, WP and TrAIL and, effective June 1, 2011 for ATSI, transmission service over Met-Ed’s, JCP&L’s and Penelec’s facilities is provided by PJM under its open access transmission tariff. The FERC also regulates unbundled transmission service to retail customers. Additionally, seeSee FERC Matters for RTO Consolidation.

Realignment below.
The FERC regulates the sale of power for resale in interstate commerce in part by granting authority to public utilities to sell wholesale power at market-based rates upon a showing that the seller cannot exert market power in generation or transmission. OE, CEI, TE, Penn, JCP&L, MetEd, Penelec, MP, WP, and PE each have been authorized by FERC to sell wholesale power in interstate commerce and have a market-based rates tariff on file with the FERC; although major wholesale purchases and sales remain subject to regulation by the relevant state commissions. AE Supply, FES, FGCO and NGC each have been authorized by the FERC to sell wholesale power in interstate commerce and have a market-based tariff on file with the FERC. By virtue of this tariff and authority to sell wholesale power, each company is regulated as a public utility under the FPA. However, consistent with its historical practice, the FERC has granted AE Supply, FES, FGCO and NGC a waiver from most of the reporting, record-keeping and accounting requirements that typically apply to traditional public utilities. Along with market-based rate authority, the FERC also granted AE Supply, FES, FGCO and NGC blanket authority to issue securities and assume liabilities under Section 204 of the FPA. As a condition to selling electricity on a wholesale basis at market-based rates, AE Supply, FES, FGCO and NGC, like all other entities granted market-based rate authority, must file electronic quarterly reports with the FERC, listing itstheir sales transactions for the prior quarter.

The nuclear generating facilities owned and leased by NGC are subject to extensive regulation by the NRC. The NRC subjects nuclear generating stations to continuing review and regulation covering, among other things, operations, maintenance, emergency planning, security and environmental and radiological aspects of those stations. The NRC may modify, suspend or revoke operating licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under such Act or the terms of the licenses. FENOC is the licensee for thesethe operating nuclear plants and has direct compliance responsibility for NRC matters. FES controls the economic dispatch of NGC’s plants. See Nuclear Regulation below.

Regulatory Accounting

The Utilities, ATSI, PATH and ATSITrAIL recognize, as regulatory assets, costs which the FERC, PUCO, PPUC MDPSC, WVPSC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. All regulatory assets are expected to be recovered from customers under the Utilities'Utilities’ respective transition and regulatory plans. Based on those plans, the Utilities, ATSI, PATH and TrAIL continue to bill and collect cost-based rates for their transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Utilities, ATSI, PATH and TrAIL continue the application of regulatory accounting to those operations.

FirstEnergy accounts for the effects of regulation through the application of regulatory accounting to its operating utilitiesthe Utilities, ATSI, PATH and TrAIL since each of their rates:rates are established by a third-party regulator with the authority to set rates that bind customers, are cost-


·are established by a third-party regulator with the authority to set rates that bind customers;
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·are cost-based; and

·based and can be charged to and collected from customers.

An enterprise meeting all of these criteria capitalizes costs that would otherwise be charged to expense (regulatory assets) if the rate actions of its regulator make it probable that those costs will be recovered in future revenue. Regulatory accounting is applied only to the parts of the business that meet the above criteria. If a portion of the business applying regulatory accounting no longer meets those requirements, previously recorded net regulatory assets are removed from the balance sheet in accordance with GAAP.

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

·restructuring the electric generation business and allowing the Utilities' customers to select a competitive electric generation supplier other than the Utilities;

·establishing or defining the PLR obligations to customers in the Utilities' service areas;

·providing the Utilities with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market;

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·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.

Reliability Initiatives

In 2005, Congress amended the FPA to provide for federally-enforceable mandatory reliability standards. TheFederally-enforceable mandatory reliability standards apply to the bulk powerelectric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES, AE Supply, FGCO, FENOC, ATSI and ATSI.TrAIL. The NERC is charged with establishingthe ERO designated by FERC to establish and enforcingenforce these reliability standards, although itNERC has delegated day-to-day implementation and enforcement of its responsibilitiesthese reliability standards to eight regional entities, including ReliabilityFirst Corporation.RFC. All of FirstEnergy’sFirstEnergy's facilities are located within the ReliabilityFirstRFC region. FirstEnergy actively participates in the NERC and ReliabilityFirstRFC stakeholder 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 RFC.

FirstEnergy believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such items are found, FirstEnergy develops information about the item and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an item to RFC. Moreover, it is clear that the NERC, ReliabilityFirstRFC and the FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with future new or amended standards cannot be determined at this time. However, thetime; however, 2005 amendments to the FPA provide that all prudent costs incurred to comply with the newfuture reliability standards be recovered in rates. Still, anyAny future inability on FirstEnergy’sFirstEnergy's part to comply with the reliability standards for its bulk power system could result in the imposition of financial penalties that 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 Midwest ISO 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. Our MISO facilities are next due for the periodic audit by ReliabilityFirst later this year.

On December 9, 2008, a transformer at JCP&L’s&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&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 based on the data submittals or interview results.with respect to this matter.

On June 5, 2009,August 23, 2010, FirstEnergy self-reported to ReliabilityFirstRFC a vegetation encroachment event on a Met-Ed 230kV line. This event did not result in a potential violationfault, outage, operation of protective equipment, or any other meaningful electric effect on any FirstEnergy transmission facilities or systems. On August 25, 2010, RFC issued a notice of enforcement to investigate the incident. FirstEnergy submitted a data response to RFC on September 27, 2010. On July 8, 2011, RFC and Met-Ed signed a settlement agreement to resolve all outstanding issues related to the vegetation encroachment event. The settlement calls for Met-Ed to pay a penalty of$650,000, and for FirstEnergy to perform certain mitigating actions. These mitigating actions include inspecting FirstEnergy's transmission system using LiDAR technology, and reporting the results of inspections, and any follow-up work, to RFC. FirstEnergy was performing the LiDAR work in response to certain other industry directives issued by NERC Standard PRC-005 resultingin 2010. NERC subsequently approved the settlement agreement and, on September 30, 2011, submitted the approved settlement to FERC for final approval. FERC approved the settlement agreement on October 28, 2011. Met-Ed subsequently paid the $650,000penalty and, on December 31, 2011, RFC sent written notice that this matter has been closed.

In 2011, RFC performed routine compliance audits of parts of FirstEnergy's bulk-power system and generally found the audited systems and process to be in full compliance with all audited reliability standards. RFC will perform additional audits in 2012.
Maryland Regulatory Matters
By statute enacted in 2007, the obligation of Maryland utilities to provide SOS to residential and small commercial customers, in exchange for recovery of their costs plus a reasonable profit, was extended indefinitely. The legislation also established a5-year cycle (to begin in 2008) for the MDPSC to report to the legislature on the status of SOS. PE now conducts rolling auctions to procure the power supply necessary to serve its customer load pursuant to a plan approved by the MDPSC. However, the terms on which PE will provide SOS to residential customers after the current settlement expires at the end of 2012 will depend on developments with respect to SOS in Maryland over the coming year, including but not limited to, possible MDPSC decisions in the proceedings discussed below.
The MDPSC opened a new docket in August 2007 to consider matters relating to possible “managed portfolio” approaches to SOS and other matters. “Phase II” of the case addressed utility purchases or construction of generation, bidding for procurement of demand response resources and possible alternatives if the TrAIL and PATH projects were delayed or defeated. It is unclear when the MDPSC will issue its findings in this proceeding.



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In September 2009, the MDPSC opened a new proceeding to receive and consider proposals for construction of new generation resources in Maryland. In December 2009, Governor Martin O'Malley filed a letter in this proceeding in which he characterized the electricity market in Maryland as a “failure” and urged the MDPSC to use its existing authority to order the construction of new generation in Maryland, vary the means used by utilities to procure generation and include more renewables in the generation mix. In December 2010, the MDPSC issued an order soliciting comments on a model RFP for solicitation of long-term energy commitments by Maryland electric utilities. PE and numerous other parties filed comments, and on September 29, 2011, the MDPSC issued an order requiring the utilities to issue the RFP crafted by the MDPSC by October 7, 2011. The RFPs were issued by the utilities as ordered by the MDPSC. The order, as amended, indicated that bids were due by January 20, 2012, and that the MDPSC would be the entity evaluating all bids. The Chairman of the MDPSC has stated publicly that several bids were received, but no other information was released. After receipt of further comments from interested parties, including PE, on January 13, 2012, a hearing on whether more generation is needed, irrespective of what bids may have been received, was held on January 31, 2012. There has been no further action on this matter.
In September 2007, the MDPSC issued an order that required the Maryland utilities to file detailed plans for how they will meet the “EmPOWER Maryland” proposal that electric consumption be reduced by10%and electricity demand be reduced by15%, in each case by 2015.

The Maryland legislature in 2008 adopted a statute codifying the EmPOWER Maryland goals. In 2008, PE filed its inabilitycomprehensive plans for attempting to validate maintenance recordsachieve those goals, asking the MDPSC to approve programs for 20 protection system relays (outresidential, commercial, industrial, and governmental customers, as well as a customer education program. The MDPSC ultimately approved the programs in August 2009 after certain modifications had been made as required by the MDPSC, and approved cost recovery for the programs in October 2009. Expenditures were estimated to be approximately$101 millionfor the PE programs for the period of approximately 20,000 reportable relays)2009 to 2015 and would be recovered over thatsixyear period. Meanwhile, after extensive meetings with the MDPSC Staff and other stakeholders, PE's plans for additional and improved programs for the period 2012-2014 were filed on August 31, 2011. The MDPSC held hearings on PE's and the other utilities' plans in JCP&L’sOctober 2011, and Penelec’s transmission systems. These potential violations were discovered duringon December 22, 2011, issued an order approving Potomac Edison's plan with various modifications and follow-up assignments. On January 23, 2012, PE filed a comprehensive field reviewRequest for Rehearing because additional facts not considered by the MDPSC demonstrate, among other things, that conservation voltage reduction program expenditures should be accorded cost recovery through the EmPOWER surcharge, as has been provided for all other EmPOWER programs as opposed to recovery of those expenditures being addressed in a future base rate case as the MDPSC found in its order.
In March 2009, the MDPSC issued an order temporarily suspending the right of all FirstEnergy substationselectric and gas utilities in the state to verifyterminate service to residential customers for non-payment of bills. The MDPSC subsequently issued an order making various rule changes relating to terminations, payment plans, and customer deposits that make it more difficult for Maryland utilities to collect deposits or to terminate service for non-payment. The MDPSC is continuing to collect data on payment plan and related issues and has adopted regulations that expand the summer and winter “severe weather” termination moratoria when temperatures are very high or very low, fromoneday, as provided by statute, tothreedays on each occurrence.
The Maryland legislature passed a bill on April 11, 2011, which requires the MDPSC to promulgate rules by July 1, 2012 that address service interruptions, downed wire response, customer communication, vegetation management, equipment inspection, and maintenance database accuracy. FirstEnergy has completed all mitigation actions, including calibrationsannual reporting. In crafting the regulations, the legislation directs the MDPSC to consider cost-effectiveness, and maintenance recordsprovides that the MDPSC may adopt different standards for different utilities based on such factors as system design and existing infrastructure, geography, and customer density. Beginning in July 2013, the MDPSC is required to assess each utility's compliance with the new rules, and may assess penalties of up to$25,000per day per violation. The MDPSC convened a working group of utilities, regulators, and other interested stakeholders to address the topics of the proposed rules. A draft of the rules was filed, along with the report of the working group, on October 27, 2011. Hearings to consider the rules and comments occurred over four days between December 8 and 15, 2011, after which revised rules were sent for legislative review. The proposed rules were published in the Maryland Register on February 24, 2012, and a deadline of March 26, 2012, was set for the relays. Reliabilityfiling of further comments. A further hearing is required before the rules could become final. Separately, on July 7, 2011, the MDPSC adopted draft rules requiring monitoring and inspections for contact voltage. The draft rules were published in September, 2011. After a further hearing in October, 2011, the final rules were re-published and became effective on November 28, 2011.First
 issued
New Jersey Regulatory Matters

On September 8, 2011, the Division of Rate Counsel filed a Petition with the NJBPU asserting that it has reason to believe that JCP&L is earning an Initial Noticeunreasonable return on its New Jersey jurisdictional rate base. The Division of Alleged Violation on June 22, 2009. The NERC approved FirstEnergy’s mitigation plan on August 19, 2009,Rate Counsel requests that the NJBPU order JCP&L to file a base rate case petition so that the NJBPU may determine whether JCP&L's current rates for electric service are just and submitted itreasonable. JCP&L filed an answer to the FERCPetition on September 28, 2011, stating, inter alia, that the Division of Rate Counsel analysis upon which it premises its Petition contains errors and inaccuracies, that JCP&L's achieved return on equity is currently within a reasonable range, and that there is no reason for approval on August 19, 2009. FirstEnergy is not ablethe NJBPU to require JCP&L to file a base rate case at this timetime.On November 30, 2011, the NJBPU ordered that the matter be assigned to predictthe NJBPU President to act as presiding officer to set and modify the schedule for this matter as appropriate, decide upon motions, and otherwise control the conduct of this case, without the need for full Board approval. The matter is pending and a schedule for further proceedings has not yet been established.
On September 22, 2011, the NJBPU ordered that JCP&L hire a Special Reliability Master, subject to NJBPU approval, to evaluate


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JCP&L's design, operating, maintenance and performance standards as they pertain to the Morristown, New Jersey underground electric distribution system, and make recommendations to JCP&L and the NJBPU on the appropriate courses of action necessary to ensure adequate reliability and safety in the Morristown underground network.On October 12, 2011, the Special Reliability Master was selected and on January 31, 2012, the project report was submitted to the Company and NJBPU Staff. On February 10, 2012, the NJBPU accepted the report and directed the Staff to present recommendations on March 12, 2012, on actions required by JCP&L to ensure the safe, reliable operation of the Morristown network.
Pursuant to a formal Notice issued by the NJBPU on September 14, 2011, public hearings were held on September 26 and 27, 2011, to solicit public comments regarding the state of preparedness and responsiveness of the local electric distribution companies prior to, during and after Hurricane Irene. By subsequent Notice issued September 28, 2011, additional hearings were held in October 2011. Additionally, the NJBPU accepted written comments through October 31, 2011 related to this inquiry.On December 4, 2011, the NJBPU Division of Reliability and Security issued a Request for Qualifications soliciting bid proposals from qualified consulting firms to provide expertise in the review and evaluation of New Jersey's electric distribution companies' preparation and restoration to Hurricane Irene and the October 2011 snowstorm. Responsive bids were submitted on January 20, 2012, and the report of selected bidder is to be submitted to the NJPBU 120 days from the date the contract is awarded. On December 14, 2011, the NJBPU Staff filed a report of its preliminary findings and recommendations with respect to the electric utility companies' planning and response to Hurricane Irene and the October 2011 snowstorm. The NJBPU has not indicated what actions or penalties,additional action, if any, that ReliabilityFirst will propose formay be taken as a result of information obtained through this self-reported violation.process.

Ohio Regulatory Matters

On June 7, 2007, theThe Ohio Companies filedoperate under an application for an increase in electric distribution rates with the PUCO and, on August 6, 2007, updated their filing. On January 21, 2009, the PUCO granted the Ohio Companies’ application in part 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 CEIESP, which expires on May 31, 2014. The material terms of the ESP include: generation supplied through a CBP commencing June 1, 2009. Applications for rehearing2011; a load cap of this order were filedno less than80%, which also applies to tranches assigned post-auction; a6%generation discount to certain low income customers provided by the Ohio Companies andthrough a bilateral wholesale contract with FES (FES is 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.

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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. The PUCO has not yet issued a substantive Entry on Rehearing.  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 servicewholesale suppliers 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 described above for April and May 2009 to the Ohio Companies for their non-shopping customers; for the period of June 1, 2009Companies); no increase in base distribution rates through May 31, 2011, retail generation prices would be based upon2014; and a new distribution rider, Rider DCR, to recover a return of, and on, capital investments in the outcome of a descending clock CBP on a slice-of-system basis.delivery system. The Amended ESP further provided that the Ohio Companies willalso agreed not seekto recover from retail customers certain costs related to transmission cost allocations by PJM as a base distribution rate increase, subject to certain exceptions, with an effective dateresult of such increase before January 1, 2012, that CEI would agree to write-off approximately $216 million of its Extended RTC regulatory asset, and that the Ohio Companies would collect a delivery service improvement rider at an overall average rate of $.002 per KWHATSI's integration into PJM for the period of April 1, 2009 through December 31, 2011. The Amended ESP also addressed a number of other issues, including but not limited to, rate design for various customer classes, and resolutionlonger of the prudence review and the collection of deferred costs that were approved in prior proceedings. On February 26, 2009, the Ohio Companies filed a Supplemental Stipulation, which was signed or not opposed by virtually all of the parties to the proceeding, that supplemented and modified certain provisions of the February 19, 2009 Stipulation and Recommendation. Specifically, the Supplemental Stipulation modified the provision relating to governmental aggregation and the Generation Service Uncollectible Rider, provided further detail on the allocation of the economic development funding contained in the Stipulation and Recommendation, and proposed additional provisions related to the collaborative process for the development of energy efficiency programs, among other provisions. The PUCO adopted and approved certain aspects of the Stipulation and Recommendation on March 4, 2009, and adopted and approved the remainder of the Stipulation and Recommendation and Supplemental Stipulation without modification on March 25, 2009. Certain aspects of the Stipulation and Recommendation and Supplemental Stipulation took effect on April 1, 2009 while the remaining provisions took effect on June 1, 2009.

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 servicefive-year period from June 1, 20092011 through May 31, 2011. FES participated in2015 or when the auction, winning 51%amount of costs avoided by customers for certain types of products totals$360 milliondependent on the outcome of certain PJM proceedings, agreed to establish a$12 millionfund to assist low income customers over the term of the tranches (one tranche equals one percent of the load supply). SubsequentESP and agreed to the signing of the wholesale contracts, four winning bidders reached separate agreements with FES with the result that FES is now responsible for providing 77% of the Ohio Companies’ total load supply.  The results of the CBP were accepted by the PUCO on May 14, 2009. FES has also separately contracted with numerous communitiesadditional matters related to provide retail generation service through governmental aggregation programs.energy efficiency and alternative energy requirements.

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

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SB221 also requires electric distribution utilities to implement energy efficiency programs. Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total annual energy savings equivalent ofto approximately166,000MWH in 2009,290,000MWH in 2010,410,000MWH in 2011,470,000MWH in 2012 and530,000MWH in 2013, with additional savings required through 2025. Utilities arewere also required to reduce peak demand in 2009 by1%, with an additional .75% 0.75%reduction each year thereafter through 2018. The PUCO may amend these benchmarks in certain, limited circumstances, and the Ohio Companies have filed an application with the PUCO seeking such amendments. As discussed below, on January 7, 2010, the PUCO amended the 2009 energy efficiency benchmarks to zero, contingent upon the Ohio Companies meeting the revised benchmarks in a period of not more than three years.  The PUCO has not yet acted upon the application seeking a reduction of the peak demand reduction requirements. 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. On

In December 15, 2009, the Ohio Companies filed the requiredthreeyear 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. The PUCO has set the matter for hearing on March 2, 2010. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers.

In October 2009, thecustomers in 2012. The PUCO issued additional Entries, modifying certain of its previous rules that set outan Opinion and Order generally approving the manner in which electric utilities, includingOhio Companies'three-year plan, and the Ohio Companies willare in the process of implementing those programs included in the Plan. OE fell short of its statutory 2010 energy efficiency and peak demand reduction benchmarks and therefore, on January 11, 2011, it requested that its 2010 energy efficiency and peak demand reduction benchmarks be requiredamended to actual levels achieved in 2010. Moreover, because the PUCO indicated, when approving the 2009 benchmark request, that it would modify the Ohio Companies' 2010 (and 2011 and 2012) energy efficiency benchmarks when addressing the portfolio plan, the Ohio Companies were not certain of their 2010 energy efficiency obligations. Therefore, CEI and TE (each of which achieved its 2010 energy efficiency and peak demand reduction statutory benchmarks) also requested an amendment if and only to the degree one was deemed necessary to bring them into compliance with their yet-to-be-defined modified benchmarks. On May 19, 2011, the PUCO granted the request to reduce the 2010 energy efficiency and peak demand reductions to the level achieved in 2010 for OE, while finding that the motion was moot for CEI and TE. On June 2, 2011, the Ohio Companies filed an application for rehearing to clarify the decision related to CEI and TE. On July 27, 2011, the PUCO denied that application for rehearing, but clarified that CEI and TE could apply for an amendment in the future for the 2010 benchmarks should it be necessary to do so. Failure to comply with the benchmarks containedor to obtain such an amendment may subject the Ohio Companies to an assessment of a penalty by the PUCO. In addition to approving the programs included in SB221the plan, with only minor modifications, the PUCO authorized the Ohio Companies to recover all costs related to the employmentoriginal CFL program that the Ohio Companies had previously suspended at the request 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 PUCO. Applications for rehearingRehearing were filed in mid-November 2009 were grantedby the Ohio Companies, Ohio Energy Group and Nucor Steel Marion, Inc. on December 9, 2009 for the sole purpose of further considerationApril 22, 2011, regarding portions of the matters raised inPUCO's decision, including the method for calculating savings and certain changes made by the PUCO to specific programs. On September 7, 2011, the PUCO denied those applications.applications for rehearing. The PUCO has not yet issuedalso included a substantive Entry on Rehearing.  The rules implementingnew standard for compliance with the requirements of SB221 went into effect on December 10, 2009. The Ohio Companies, on October 27, 2009, submitted an application to amend their 2009 statutory energy efficiency benchmarks by requiring electric distribution companies to zero. offer “all available cost effective energy efficiency opportunities” regardless of their level of compliance with the benchmarks as set forth in the statute.On JanuaryOctober 7, 2010,2011, the Ohio Companies, the Industrial Energy Users - Ohio, and the Ohio Energy Group filed applications for rehearing, arguing that the PUCO'S new standard is unlawful. The Ohio Companies also asked the PUCO issued an Order granting the Companies’ request to amend thewithdraw its amendment of CEI's and TE's 2010 energy efficiency benchmarks. The PUCO did not rule on the Applications for Rehearing within thirty days, thus denying them by operation of law. On December 30, 2011, the Ohio Companies filed a notice of appeal with the Supreme Court of Ohio, challenging the PUCO's new standard. No procedural schedule has been established.


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Additionally, under SB221, electric utilities and electric service companies are required to serve part of their load in 2011 from renewable energy resources equivalent to 0.25%1.00%of the average of the KWH they serveserved in 2009.2008-2010; in 2012 from renewable energy resources equivalent to1.50%of the average of the KWH they served in 2009-2011; and in 2013 from renewable energy resources equivalent to2.00%of the average of the KWH they served in 2010-2012. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RFPs sought renewable energy RECs, including solar RECs and RECs generated in Ohio in order to meet the Ohio Companies’ alternative energy requirements set forth in SB221. The RECs acquired through thesetwoRFPs will bewere used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. In March 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market and reduced the Ohio Companies' aggregate 2009 benchmark to the level of SRECs the Ohio Companies acquired through their 2009 RFP processes, provided the Ohio Companies' 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC benchmark. On December 7, 2009,April 15, 2011, the Ohio Companies filed an application seeking an amendment to each of their 2010 alternative energy requirements for solar RECs generated in Ohio on the basis that an insufficient quantity of solar resources are available in the market but reflecting solar RECs that they have obtained and providing additional information regarding efforts to secure solar RECs. On August 3, 2011, the PUCO granted the Ohio Companies' force majeure request for 2010 and increased their 2011 benchmark by the amount of SRECs generated in Ohio that the Ohio Companies were short in 2010. On September 2, 2011, the Environmental Law and Policy Center and Nucor Steel Marion, Inc. filed applications for rehearing. The Ohio Companies filed their response on September 12, 2011. These applications for rehearing were denied by the PUCO on September 20, 2011, but as part of its Entry on Rehearing the PUCO opened a new docket to review the Ohio Companies' alternative energy recovery rider. Separately,oneparty has filed a request that the PUCO audit the cost of the Ohio Companies' compliance with the alternative energy requirements and the Ohio Companies' compliance with Ohio law. The PUCO selected auditors to perform a financial and a management audit, and final audit reports are to be filed with the PUCO seeking a force majeure determination regarding the Ohio Companies’ compliance with the 2009 solar energy resources benchmark, and seeking a reduction in the benchmark.  The PUCO has not yet ruled on that application.

On October 20, 2009,by May 15, 2012. In August 2011, the Ohio Companies filed an MROconducted two RFP processes to procure electric generation serviceobtain RECs to meet the statutory benchmarks 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 supplier2011 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. Enhancements to the May 2009 CBP, the MRO would include multiple bidding sessions and multiple products with different delivery periods for generation supply features which are designed to reduce potential price volatility and reduce supplier risk and encourage bidder participation. A technical conference was held on October 29, 2009. Hearings took place in December and the 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. Although the Ohio Companies requested a PUCO determination by January 18, 2010, on February 3, 2010, the PUCO announced that its determination would be delayed. Under a determination that such statutory requirements are met, the Ohio Companies would be able to implement the MRO and conduct the CBP.beyond.

PennsylvaniaNew Jersey Regulatory Matters

Met-EdOn September 8, 2011, the Division of Rate Counsel filed a Petition with the NJBPU asserting that it has reason to believe that JCP&L is earning an unreasonable return on its New Jersey jurisdictional rate base. The Division of Rate Counsel requests that the NJBPU order JCP&L to file a base rate case petition so that the NJBPU may determine whether JCP&L's current rates for electric service are just and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG energyreasonable. JCP&L filed an answer to the marketPetition on September 28, 2011, stating, inter alia, that the Division of Rate Counsel analysis upon which it premises its Petition contains errors and requires FESinaccuracies, that JCP&L's achieved return on equity is currently within a reasonable range, and that there is no reason for the NJBPU to provide energyrequire JCP&L to file a base rate case at fixed prices to replace any NUG energy soldthis time.On November 30, 2011, the NJBPU ordered that the matter be assigned to the extent neededNJBPU President to act as presiding officer to set and modify the schedule for Met-Edthis matter as appropriate, decide upon motions, and Penelecotherwise control the conduct of this case, without the need for full Board approval. The matter is pending and a schedule for further proceedings has not yet been established.
On September 22, 2011, the NJBPU ordered that JCP&L hire a Special Reliability Master, subject to satisfy their PLR and default service obligations.NJBPU approval, to evaluate


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JCP&L's design, operating, maintenance and performance standards as they pertain to the Morristown, New Jersey underground electric distribution system, and make recommendations to JCP&L and the NJBPU on the appropriate courses of action necessary to ensure adequate reliability and safety in the Morristown underground network.On October 12, 2011, the Special Reliability Master was selected and on January 31, 2012, the project report was submitted to the Company and NJBPU Staff. On February 20, 2009, Met-Ed10, 2012, the NJBPU accepted the report and Penelec filed withdirected the PPUC a generation procurement plan covering the period January 1, 2011 through May 31, 2013. The plan is designedStaff to provide adequate and reliable service via a prudent mix of long-term, short-term and spot market generation supply, aspresent recommendations on March 12, 2012, on actions required by Act 129. The plan proposed a staggered procurement schedule, which varies by customer class, throughJCP&L to ensure the use of a descending clock auction. 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 andsafe, 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. On September 2, 2009, the ALJ issued a Recommended Decision (RD) approving the settlement and adopted Met-Ed and Penelec’s positions on two reserved issues. On November 6, 2009, the PPUC entered an Order approving the settlement and finding in favor of Met-Ed and Penelec on the two reserved issues.  Generation procurement began in January 2010.

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On May 22, 2008, the PPUC approved 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 portionoperation of the projected costs ($92 million) plus carrying charges for recovery through future TSCsMorristown network.
Pursuant to a formal Notice issued by December 31, 2010. Various intervenors filed complaints against those filings. In addition, the PPUC ordered an investigationNJBPU on September 14, 2011, public hearings were held on September 26 and 27, 2011, to reviewsolicit public comments regarding the reasonablenessstate 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 investigationpreparedness 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.  On January 28, 2010, the PPUC adopted a motion which denies the recovery of marginal transmission losses through the TSC for the period of June 1, 2007 through March 31, 2008, and instructs Met-Ed and Penelec to work with the parties and file a petition to retain any over-collection, with interest, until 2011 for the purpose of providing mitigation of future rate increases starting in 2011 for their customers.  Met-Ed and Penelec are now awaiting an order, which is expected to be consistent with the motion. If so, Met-Ed and Penelec plan to appeal such a decision to the Commonwealth Court of Pennsylvania. Although the ultimate outcome of this matter cannot be determined at this time, it is the beliefresponsiveness of the local electric distribution companies that they should prevail in any such appeal and therefore expect to fully recover the approximately $170.5 million ($138.7 million for Met-Ed and $31.8 million for Penelec) in marginal transmission losses for the period prior to, January 1, 2011.

On Mayduring and after Hurricane Irene. By subsequent Notice issued September 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, subject to the outcome of the proceeding related to the 2008 TSC filing described above. 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 the2011, 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.

Act 129 became effective in 2008 and addresses 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 requires each Pennsylvania utility to file with the PPUC an energy efficiency and peak load reduction 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. 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 Pennsylvania Companies filed revised EE&C Plans on September 21, 2009. In an October 28, 2009 Order, the PPUC approved in part, and rejected in part, the Pennsylvania Companies' filing. Following additional filings related to the plans, including modifications as requested by the PPUC. The PPUC issued an order on January 28, 2010, approving, in part, and rejecting, in part the Pennsylvania Companies’ modified plans.  The Pennsylvania Companies filed final plans and tariff revisions on February 5, 2010 consistent with the minor revisions required by the PPUC.  The PPUC must approve or reject the plans within 60 days.

Act 129 also required utilities to file by August 14, 2009 with the PPUC smart meter technology procurement and installation plan to provide for the installation of smart meter technology within 15 years. On August 14, 2009, Met-Ed, Penelec and Penn jointly filed a Smart Meter Technology Procurement and Installation Plan. Consistent with the PPUC’s rules, 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. A Technical Conference and evidentiary hearings were held in November 2009. BriefsOctober 2011. Additionally, the NJBPU accepted written comments through October 31, 2011 related to this inquiry.On December 4, 2011, the NJBPU Division of Reliability and Security issued a Request for Qualifications soliciting bid proposals from qualified consulting firms to provide expertise in the review and evaluation of New Jersey's electric distribution companies' preparation and restoration to Hurricane Irene and the October 2011 snowstorm. Responsive bids were submitted on January 20, 2012, and the report of selected bidder is to be submitted to the NJPBU 120 days from the date the contract is awarded. On December 14, 2011, the NJBPU Staff filed a report of its preliminary findings and recommendations with respect to the electric utility companies' planning and response to Hurricane Irene and the October 2011 snowstorm. The NJBPU has not indicated what additional action, if any, may be taken as a result of information obtained through this process.
Ohio Regulatory Matters
The Ohio Companies operate under an ESP, which expires on December 11, 2009, and Reply Briefs were filed on DecemberMay 31, 2009. An Initial Decision was issued2014. The material terms of the ESP include: generation supplied through a CBP commencing June 1, 2011; a load cap of no less than80%, which also applies to tranches assigned post-auction; a6%generation discount to certain low income customers provided by the presiding ALJOhio Companies through a bilateral wholesale contract with FES (FES is one of the wholesale suppliers to the Ohio Companies); no increase in base distribution rates through May 31, 2014; and a new distribution rider, Rider DCR, to recover a return of, and on, January 28, 2010.  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 listedcapital investments in the Commission’s Implementation Order; eliminating the provisiondelivery system. The Ohio Companies also agreed not to recover from retail customers certain costs related to transmission cost allocations by PJM as a result of interest in the 1307(e) reconciliation; providingATSI's integration into PJM 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.  Exceptions are due on February 17, 2010, and Reply Exceptions are due on March 1.  The Pennsylvania Companies expect the PPUC to act on the plans in early 2010.

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Legislation addressing rate mitigation and the expiration of rate caps has been introduced in both the 2008 and 2009 legislative sessions. The final form of such legislation and its possible impact on the Pennsylvania Companies’ business and operations are uncertain.

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

On March 31, 2009, Met-Ed and Penelec submitted their 5-year NUG Statement Compliance filing to the PPUC in accordance with their 1998 Restructuring Settlement originally entered into with the PPUC pursuant to comprehensive electric utility industry restructuring legislation (Customer Choice Act)  adopted in Pennsylvania in 1996.  In the compliance filing, Met-Ed proposed to reduce its CTC rate for the residential class with a corresponding increase in the generation rate and the shopping credit, and Penelec proposed to reduce its CTC rate to zero for all classes with a corresponding increase in the generation rate and the shopping credit. While these changes would result in additional annual generation revenue (Met-Ed - $27 million and Penelec - $59 million), overall rates would remain unchanged. On July 30, 2009, the PPUC entered an order approving the 5-year NUG Statement, approving the reductionlonger of the CTC, and directing Met-Ed and Penelec to file a tariff supplement implementing this change. On July 31, 2009, Met-Ed and Penelec filed tariff supplements decreasing the CTC rate in compliance with the July 30, 2009 order, and increasing the generation rate in compliance with the companies’ Restructuring Orders of 1998. On August 14, 2009, the PPUC approved Met-Ed and Penelec’s compliance filings.

By Tentative Order entered September 17, 2009, the PPUC provided for an additional 30-day commentfive-year 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, 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 filed comments objecting to the above accounting method utilized by Met-Ed and Penelec. Met-Ed and Penelec filed reply comments on October 26, 2009. On November 5, 2009, the PPUC issued a Secretarial Letter allowing parties to file reply comments to Met-Ed and Penelec’s reply comments by November 16, 2009, and reply comments were filed by the Office of Consumer Advocate, ARIPPA, and the Met-Ed Industrial Users Group and Penelec Industrial Customer Alliance.  Met-Ed and Penelec are awaiting further action by the Commission.

On February 8, 2010, Penn filed with the PPUC a generation procurement plan covering the periodfrom June 1, 2011 through May 31, 2013.2015 or when the amount of costs avoided by customers for certain types of products totals$360 milliondependent on the outcome of certain PJM proceedings, agreed to establish a$12 millionfund to assist low income customers over the term of the ESP and agreed to additional matters related to energy efficiency and alternative energy requirements.

Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total annual energy savings equivalent to approximately166,000MWH in 2009,290,000MWH in 2010,410,000MWH in 2011,470,000MWH in 2012 and530,000MWH in 2013, with additional savings required through 2025. Utilities were also required to reduce peak demand in 2009 by1%, with an additional0.75%reduction each year thereafter through 2018.

In December 2009, the Ohio Companies filed the requiredthreeyear 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. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers in 2012. The PUCO issued an Opinion and Order generally approving the Ohio Companies'three-year plan, is designedand the Ohio Companies are in the process of implementing those programs included in the Plan. OE fell short of its statutory 2010 energy efficiency and peak demand reduction benchmarks and therefore, on January 11, 2011, it requested that its 2010 energy efficiency and peak demand reduction benchmarks be amended to provide adequateactual levels achieved in 2010. Moreover, because the PUCO indicated, when approving the 2009 benchmark request, that it would modify the Ohio Companies' 2010 (and 2011 and reliable service through a prudent mix2012) energy efficiency benchmarks when addressing the portfolio plan, the Ohio Companies were not certain of long-term, short-termtheir 2010 energy efficiency obligations. Therefore, CEI and spot market generation supply, as required by Act 129. The plan proposed a staggered procurement schedule,TE (each of which varies by customer class, throughachieved its 2010 energy efficiency and peak demand reduction statutory benchmarks) also requested an amendment if and only to the usedegree one was deemed necessary to bring them into compliance with their yet-to-be-defined modified benchmarks. On May 19, 2011, the PUCO granted the request to reduce the 2010 energy efficiency and peak demand reductions to the level achieved in 2010 for OE, while finding that the motion was moot for CEI and TE. On June 2, 2011, the Ohio Companies filed an application for rehearing to clarify the decision related to CEI and TE. On July 27, 2011, the PUCO denied that application for rehearing, but clarified that CEI and TE could apply for an amendment in the future for the 2010 benchmarks should it be necessary to do so. Failure to comply with the benchmarks or to obtain such an amendment may subject the Ohio Companies to an assessment of a descending clock auction.penalty by the PUCO. In addition to approving the programs included in the plan, with only minor modifications, the PUCO authorized the Ohio Companies to recover all costs related to the original CFL program that the Ohio Companies had previously suspended at the request of the PUCO. Applications for Rehearing were filed by the Ohio Companies, Ohio Energy Group and Nucor Steel Marion, Inc. on April 22, 2011, regarding portions of the PUCO's decision, including the method for calculating savings and certain changes made by the PUCO to specific programs. On September 7, 2011, the PUCO denied those applications for rehearing. The PPUCPUCO also included a new standard for compliance with the statutory energy efficiency benchmarks by requiring electric distribution companies to offer “all available cost effective energy efficiency opportunities” regardless of their level of compliance with the benchmarks as set forth in the statute.On October 7, 2011, the Ohio Companies, the Industrial Energy Users - Ohio, and the Ohio Energy Group filed applications for rehearing, arguing that the PUCO'S new standard is unlawful. The Ohio Companies also asked the PUCO to withdraw its amendment of CEI's and TE's 2010 energy efficiency benchmarks. The PUCO did not rule on the Applications for Rehearing within thirty days, thus denying them by operation of law. On December 30, 2011, the Ohio Companies filed a notice of appeal with the Supreme Court of Ohio, challenging the PUCO's new standard. No procedural schedule has been established.


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Additionally, under SB221, electric utilities and electric service companies are required to issueserve part of their load in 2011 from renewable energy resources equivalent to1.00%of the average of the KWH they served in 2008-2010; in 2012 from renewable energy resources equivalent to1.50%of the average of the KWH they served in 2009-2011; and in 2013 from renewable energy resources equivalent to2.00%of the average of the KWH they served in 2010-2012. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RECs acquired through thesetwoRFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. In March 2010, the PUCO found that there was an orderinsufficient quantity of solar energy resources reasonably available in the market and reduced the Ohio Companies' aggregate 2009 benchmark to the level of SRECs the Ohio Companies acquired through their 2009 RFP processes, provided the Ohio Companies' 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC benchmark. On April 15, 2011, the Ohio Companies filed an application seeking an amendment to each of their 2010 alternative energy requirements for solar RECs generated in Ohio on the plan no later than November 8,basis that an insufficient quantity of solar resources are available in the market but reflecting solar RECs that they have obtained and providing additional information regarding efforts to secure solar RECs. On August 3, 2011, the PUCO granted the Ohio Companies' force majeure request for 2010 and increased their 2011 benchmark by the amount of SRECs generated in Ohio that the Ohio Companies were short in 2010. On September 2, 2011, the Environmental Law and Policy Center and Nucor Steel Marion, Inc. filed applications for rehearing. The Ohio Companies filed their response on September 12, 2011. These applications for rehearing were denied by the PUCO on September 20, 2011, but as part of its Entry on Rehearing the PUCO opened a new docket to review the Ohio Companies' alternative energy recovery rider. Separately,oneparty has filed a request that the PUCO audit the cost of the Ohio Companies' compliance with the alternative energy requirements and the Ohio Companies' compliance with Ohio law. The PUCO selected auditors to perform a financial and a management audit, and final audit reports are to be filed with the PUCO by May 15, 2012. In August 2011, the Ohio Companies conducted two RFP processes to obtain RECs to meet the statutory benchmarks for 2011 and beyond.

New Jersey Regulatory Matters

On September 8, 2011, the Division of Rate Counsel filed a Petition with the NJBPU asserting that it has reason to believe that JCP&L is permitted to defer for future collection from customersearning an unreasonable return on its New Jersey jurisdictional rate base. The Division of Rate Counsel requests that 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 December 30, 2009, the accumulated deferred cost balance totaled approximately $98 million.

In accordance with an April 28, 2004 NJBPU order JCP&L filed testimony on June 7, 2004, supporting continuation ofto file a base rate case petition so that the NJBPU may determine whether JCP&L's current levelrates for electric service are just and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. TMI-2 is a retired nuclear facility owned by JCP&L. On September 30, 2004,reasonable. 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) comparedanswer to the estimated $528 million (in 2003 dollars) fromPetition on September 28, 2011, stating, inter alia, that the prior 1995 decommissioning study. The DPA filed commentsDivision of Rate Counsel analysis upon which it premises its Petition contains errors and inaccuracies, that JCP&L's achieved return on February 28, 2005 requestingequity is currently within a reasonable range, and that decommissioning fundingthere is no reason for the NJBPU to require JCP&L to file a base rate case at this time.On November 30, 2011, the NJBPU ordered that the matter be suspended. On March 18, 2005, JCP&L filed a responseassigned to those comments. JCP&L respondedthe NJBPU President to additional NJBPU staff discovery requests in Mayact as presiding officer to set and November 2007 and also submitted comments inmodify the proceeding in November 2007. A schedule for this matter as appropriate, decide upon motions, and otherwise control the conduct of this case, without the need for full Board approval. The matter is pending and a schedule for further NJBPU proceedings has not yet been set. established.
On March 13, 2009,September 22, 2011, the NJBPU ordered that JCP&L hire a Special Reliability Master, subject to NJBPU approval, to evaluate


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JCP&L's design, operating, maintenance and performance standards as they pertain to the Morristown, New Jersey underground electric distribution system, and make recommendations to JCP&L and the NJBPU on the appropriate courses of action necessary to ensure adequate reliability and safety in the Morristown underground network.On October 12, 2011, the Special Reliability Master was selected and on January 31, 2012, the project report was submitted to the Company and NJBPU Staff. On February 10, 2012, the NJBPU accepted the report and directed the Staff to present recommendations on March 12, 2012, on actions required by JCP&L to ensure the safe, reliable operation of the Morristown network.
Pursuant to a formal Notice issued by the NJBPU on September 14, 2011, public hearings were held on September 26 and 27, 2011, to solicit public comments regarding the state of preparedness and responsiveness of the local electric distribution companies prior to, during and after Hurricane Irene. By subsequent Notice issued September 28, 2011, additional hearings were held in October 2011. Additionally, the NJBPU accepted written comments through October 31, 2011 related to this inquiry.On December 4, 2011, the NJBPU Division of Reliability and Security issued a Request for Qualifications soliciting bid proposals from qualified consulting firms to provide expertise in the review and evaluation of New Jersey's electric distribution companies' preparation and restoration to Hurricane Irene and the October 2011 snowstorm. Responsive bids were submitted on January 20, 2012, and the report of selected bidder is to be submitted to the NJPBU 120 days from the date the contract is awarded. On December 14, 2011, the NJBPU Staff filed a report of its preliminary findings and recommendations with respect to the electric utility companies' planning and response to Hurricane Irene and the October 2011 snowstorm. The NJBPU has not indicated what additional action, if any, may be taken as a result of information obtained through this process.
Ohio Regulatory Matters
The Ohio Companies operate under an ESP, which expires on May 31, 2014. The material terms of the ESP include: generation supplied through a CBP commencing June 1, 2011; a load cap of no less than80%, which also applies to tranches assigned post-auction; a6%generation discount to certain low income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (FES is one of the wholesale suppliers to the Ohio Companies); no increase in base distribution rates through May 31, 2014; and a new distribution rider, Rider DCR, to recover a return of, and on, capital investments in the delivery system. The Ohio Companies also agreed not to recover from retail customers certain costs related to transmission cost allocations by PJM as a result of ATSI's integration into PJM for the longer of the five-year period from June 1, 2011 through May 31, 2015 or when the amount of costs avoided by customers for certain types of products totals$360 milliondependent on the outcome of certain PJM proceedings, agreed to establish a$12 millionfund to assist low income customers over the term of the ESP and agreed to additional matters related to energy efficiency and alternative energy requirements.

Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total annual SBC Petitionenergy savings equivalent to approximately166,000MWH in 2009,290,000MWH in 2010,410,000MWH in 2011,470,000MWH in 2012 and530,000MWH in 2013, with additional savings required through 2025. Utilities were also required to reduce peak demand in 2009 by1%, with an additional0.75%reduction each year thereafter through 2018.

In December 2009, the Ohio Companies filed the requiredthreeyear 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. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers in 2012. The PUCO issued an Opinion and Order generally approving the Ohio Companies'three-year plan, and the Ohio Companies are in the process of implementing those programs included in the Plan. OE fell short of its statutory 2010 energy efficiency and peak demand reduction benchmarks and therefore, on January 11, 2011, it requested that its 2010 energy efficiency and peak demand reduction benchmarks be amended to actual levels achieved in 2010. Moreover, because the PUCO indicated, when approving the 2009 benchmark request, that it would modify the Ohio Companies' 2010 (and 2011 and 2012) energy efficiency benchmarks when addressing the portfolio plan, the Ohio Companies were not certain of their 2010 energy efficiency obligations. Therefore, CEI and TE (each of which achieved its 2010 energy efficiency and peak demand reduction statutory benchmarks) also requested an amendment if and only to the degree one was deemed necessary to bring them into compliance with their yet-to-be-defined modified benchmarks. On May 19, 2011, the PUCO granted the request to reduce the 2010 energy efficiency and peak demand reductions to the level achieved in 2010 for OE, while finding that the motion was moot for CEI and TE. On June 2, 2011, the Ohio Companies filed an application for rehearing to clarify the decision related to CEI and TE. On July 27, 2011, the PUCO denied that application for rehearing, but clarified that CEI and TE could apply for an amendment in the future for the 2010 benchmarks should it be necessary to do so. Failure to comply with the NJBPUbenchmarks or to obtain such an amendment may subject the Ohio Companies to an assessment of a penalty by the PUCO. In addition to approving the programs included in the plan, with only minor modifications, the PUCO authorized the Ohio Companies to recover all costs related to the original CFL program that includesthe Ohio Companies had previously suspended at the request of the PUCO. Applications for Rehearing were filed by the Ohio Companies, Ohio Energy Group and Nucor Steel Marion, Inc. on April 22, 2011, regarding portions of the PUCO's decision, including the method for calculating savings and certain changes made by the PUCO to specific programs. On September 7, 2011, the PUCO denied those applications for rehearing. The PUCO also included a requestnew standard for compliance with the statutory energy efficiency benchmarks by requiring electric distribution companies to offer “all available cost effective energy efficiency opportunities” regardless of their level of compliance with the benchmarks as set forth in the statute.On October 7, 2011, the Ohio Companies, the Industrial Energy Users - Ohio, and the Ohio Energy Group filed applications for rehearing, arguing that the PUCO'S new standard is unlawful. The Ohio Companies also asked the PUCO to withdraw its amendment of CEI's and TE's 2010 energy efficiency benchmarks. The PUCO did not rule on the Applications for Rehearing within thirty days, thus denying them by operation of law. On December 30, 2011, the Ohio Companies filed a reductionnotice of appeal with the Supreme Court of Ohio, challenging the PUCO's new standard. No procedural schedule has been established.


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Additionally, under SB221, electric utilities and electric service companies are required to serve part of their load in 2011 from renewable energy resources equivalent to1.00%of the average of the KWH they served in 2008-2010; in 2012 from renewable energy resources equivalent to1.50%of the average of the KWH they served in 2009-2011; and in 2013 from renewable energy resources equivalent to2.00%of the average of the KWH they served in 2010-2012. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RECs acquired through thesetwoRFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. In March 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market and reduced the Ohio Companies' aggregate 2009 benchmark to the level of recoverySRECs the Ohio Companies acquired through their 2009 RFP processes, provided the Ohio Companies' 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC benchmark. On April 15, 2011, the Ohio Companies filed an application seeking an amendment to each of TMI-2 decommissioning costs basedtheir 2010 alternative energy requirements for solar RECs generated in Ohio on the basis that an updated TMI-2 decommissioning cost analysis dated January 2009. This matter is currently pending beforeinsufficient quantity of solar resources are available in the NJBPU.

New Jersey statutes requiremarket but reflecting solar RECs that they have obtained and providing additional information regarding efforts to secure solar RECs. On August 3, 2011, the PUCO granted the Ohio Companies' force majeure request for 2010 and increased their 2011 benchmark by the amount of SRECs generated in Ohio that the state periodically undertakeOhio Companies were short in 2010. On September 2, 2011, the Environmental Law and Policy Center and Nucor Steel Marion, Inc. filed applications for rehearing. The Ohio Companies filed their response on September 12, 2011. These applications for rehearing were denied by the PUCO on September 20, 2011, but as part of its Entry on Rehearing the PUCO opened a planning process, known asnew docket to review the EMP, to addressOhio Companies' alternative energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvementrecovery rider. Separately,oneparty has filed a request that the PUCO audit the cost of the Governor’s OfficeOhio Companies' compliance with the alternative energy requirements and the Governor’s Office of Economic Growth,Ohio Companies' compliance with Ohio law. The PUCO selected auditors to perform a financial and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU Presidentmanagement audit, and includes representatives of several State departments. The EMP was issued on October 22, 2008, establishing five major goals:

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·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 plansfinal audit reports are due to be filed with the NJBPUPUCO by JulyMay 15, 2012. In August 2011, the Ohio Companies conducted two RFP processes to obtain RECs to meet the statutory benchmarks for 2011 and beyond.
Pennsylvania Regulatory Matters
The PPUC entered an Order on March 3, 2010 that denied the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2010. At this time, FirstEnergy2007 through March 31, 2008, directed Met-Ed and JCP&L cannot determinePenelec to submit a new tariff or tariff supplement reflecting the impact, if any,removal of marginal transmission losses from the EMP may have on their business or operations.

TSC, and instructed Met-Ed and Penelec to work with the various intervening parties to file a recommendation to the PPUC regarding the establishment of a separate account for all marginal transmission losses collected from customers plus interest to be used to mitigate future generation rate increases beginning January 1, 2011. In support of former New Jersey Governor Corzine's Economic AssistanceMarch 2010, Met-Ed and Recovery Plan, JCP&L announcedPenelec filed a proposal to spend approximately $98 million on infrastructure and energy efficiency projects in 2009. UnderPetition with 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 programsPPUC requesting that would complement those currently being offered. The project relating to expansionit stay the portion of the existing demand response programs wasMarch 3, 2010 Order requiring the filing of tariff supplements to end collection of costs for marginal transmission losses. The PPUC granted the requested stay until December 31, 2010. Pursuant to the PPUC's order, Met-Ed and Penelec filed plans to establish separate accounts for marginal transmission loss revenues and related interest and carrying charges. Pursuant to the plan approved by the NJBPU on August 19, 2009,PPUC, Met-Ed and implementationPenelec began to refund those amounts to customers in 2009. ApprovalJanuary 2011, and the refunds are continuing over a 29 month period until the full amounts previously recovered for marginal transmission loses are refunded. In April 2010, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania appealing the PPUC's March 3, 2010 Order. On June 14, 2011, the Commonwealth Court issued an opinion and order affirming the PPUC's Order to the extent that it holds that line loss costs are not transmission costs and, therefore, the approximately$254 millionin marginal transmission losses and associated carrying charges for the $11 million project relatedperiod prior to energy efficiency programs intended to complement those currently being offered was denied by the NJBPU on DecemberJanuary 1, 2009. Implementation2011, are not recoverable under Met-Ed's and Penelec's TSC riders. Met-Ed and Penelec filed a Petition for Allowance of the remaining projects is dependent upon resolution of regulatory issues between the NJBPU and JCP&L including recovery of the costs associatedAppeal with the proposal.

On February 11, 2010, S&P downgradedPennsylvania Supreme Court and also a complaint seeking relief in the senior unsecured debtU.S. District Court for the Eastern District of FirstEnergy Corp.Pennsylvania, which was subsequently amended. The PPUC filed a Motion to BB+.  AsDismiss Met-Ed's and Penelec's Amended Complaint on September 15, 2011. Met-Ed and Penelec filed a result, pursuantResponsive brief in Opposition to the requirements of a pre-existing NJBPU order, JCP&L filed,PPUC's Motion to Dismiss on February 17, 2010, a plan addressingOctober 11, 2011. Although the mitigation of any effect of the downgrade and provided an assessment of present and future liquidity necessary to assure JCP&L’s continued payment to BGS suppliers.  The order also provides that the NJBPU should: 1) within 10 days of that filing, hold a public hearing to review the plan and consider the available options and 2) within 30 days of that filing issue an order with respect to the matter.  At this time, the public hearing has not been scheduled and FirstEnergy and JCP&L cannot determine the impact, if any, these proceedings will have on their operations.

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. 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, with another Company, filed an additional settlement agreement with FERC to resolve their outstanding claims. FirstEnergy is actively pursuing settlement agreements with other parties to the case.  On December 8, 2009, certain parties sought a writ of mandamus from the DC Circuit Court of Appeals directing FERC to issue an order on the Initial Decision. The Court agreed to hold this matter in abeyance based upon FERC’s representation to use good faith efforts to issue a substantive ruling on the initial decision no later than May 27, 2010.  If FERC fails to act, the case will be submitted for briefing in June. Theultimate outcome of this matter cannot be predicted.determined at this time, Met-Ed and Penelec believe that they should ultimately prevail through the judicial process and therefore expect to fully recover the approximately$254 million($189 millionfor Met-Ed and$65 millionfor Penelec) in marginal transmission losses for the period prior to January 1, 2011.

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In each of May 2008, 2009 and 2010, the PPUC approved Met-Ed's and Penelec's annual updates to their TSC rider for the annual periods between June 1, 2008 to 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 PPUC's approval in May 2010 authorized an increase to the TSC for Met-Ed's customers to provide for full recovery by December 31, 2010.

In February 2010, Penn filed a Petition for Approval of its DSP for the period June 1, 2011 through May 31, 2013. In July 2010, the parties to the proceeding filed a Joint Petition for Settlement of all issues. Although the PPUC's Order approving the Joint Petition held that the provisions relating to the recovery of MISO exit fees and one-time PJM integration costs (resulting from Penn's June 1, 2011 exit from MISO and integration into PJM) were approved, it made such provisions subject to the approval of cost recovery by FERC. Therefore, Penn may not put these provisions into effect until FERC has approved the recovery and allocation of MISO exit fees and PJM integration costs.

Pennsylvania adopted Act 129 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, (EE&C Plan), by July 1, 2009, setting forth the utilities' plans to reduce energy consumption by a minimum of1%and3%by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a


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minimum of4.5%by May 31, 2013. Act 129 provides for potentially significant financial penalties to be assessed upon utilities that fail to achieve the required reductions in consumption and peak demand. Act 129 also required utilities to file a SMIP with the PPUC.

The PPUC entered an Order in February 2010 giving final approval to all aspects of the EE&C Plans of Met-Ed, Penelec and Penn and the tariff rider became effective March 1, 2010. On February 18, 2011, the companies filed a petition to approve their First Amended EE&C Plans. On June 28, 2011, a hearing on the petition was held before an ALJ.On December 15, 2011, the ALJ recommended that the amended plans be approved as proposed, and on January 12, 2012, the Commission approved the plans.
WP filed its original EE&C Plan in June 2009, which the PPUC approved, in large part, by Opinion and Order entered in October 2009. In September 2010, WP filed an amended EE&C Plan that is less reliant on smart meter deployment, which the PPUC approved in January 2011.
On August 9, 2011, WP filed a petition to approve its Second Amended EE&C Plan. The proposed Second Revised Plan includes measures and a new program and implementation strategies consistent with the successful EE&C programs of Met-Ed, Penelec and Penn that are designed to enable WP to achieve the post-2011 Act 129 EE&C requirements.On January 6, 2012, a Joint Petition for Settlement of all issues was filed by the parties to the proceeding.

The Pennsylvania Companies submitted a preliminary report on July 15, 2011, and a final report on November 15, 2011, in which they reported on their compliance with statutory May 31, 2011, energy efficiency benchmarks.Met-Ed, Penelec and Penn achieved the 2011 benchmarks; however WP has been unable to provide final results because several customers are still accumulating necessary documentation for projects that may qualify for inclusion in the final results. Preliminary numbers indicate that WP did not achieve its 2011 benchmark and it is not known at this time whether WP will be subject to a fine for failure to achieve the benchmark. WP is unable to predict the outcome of this matter or estimate any possible loss or range of loss.

In December 2009, WP filed a motion to reopen the evidentiary record to submit an alternative smart meter plan proposing, among other things, a less-rapid deployment of smart meters.

In light of the significant expenditures that would be associated with its smart meter deployment plans and related infrastructure upgrades, as well as its evaluation of recent PPUC decisions approving less-rapid deployment proposals by other utilities, WP re-evaluated its Act 129 compliance strategy, including both its plans with respect to smart meter deployment and certain smart meter dependent aspects of the EE&C Plan. In October 2010, WP and Pennsylvania's OCA filed a Joint Petition for Settlement addressing WP's smart meter implementation plan with the PPUC. Under the terms of the proposed settlement, WP proposed to decelerate its previously contemplated smart meter deployment schedule and to target the installation of approximately25,000smart meters in support of its EE&C Plan, based on customer requests, by mid-2012. The proposed settlement also contemplates that WP take advantage of the30-month grace period authorized by the PPUC to continue WP's efforts to re-evaluate full-scale smart meter deployment plans. WP currently anticipates filing its plan for full-scale deployment of smart meters in June 2012. Under the terms of the proposed settlement, WP would be permitted to recover certain previously incurred and anticipated smart-meter related expenditures through a levelized customer surcharge, with certain expenditures amortized over a ten-year period. Additionally, WP would be permitted to seek recovery of certain other costs as part of its revised SMIP that it currently intends to file in June 2012, or in a future base distribution rate case.
Following additional proceedings, on March 9, 2011, WP submitted an Amended Joint Petition for Settlement which restates the Joint Petition for Settlement filed in October 2010, adds the PPUC's Office of Trial Staff as a signatory party, and confirms the support or non-opposition of all parties to the settlement.Oneparty retained the ability to challenge the recovery of amounts spent on WP's original smart meter implementation plan. A Joint Stipulation with the OSBA was also filed on March 9, 2011. The PPUC approved the Amended Joint Petition for Full Settlement by order entered June 30, 2011.

By Tentative Order entered in September 2009, the PPUC provided for an additional30-day comment period on whether the 1998 Restructuring Settlement, which addressed how Met-Ed and Penelec were going to implement direct access to a competitive market for the generation of electricity, allows Met-Ed and Penelec to apply over-collection of NUG costs for select and isolated months to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists. In response to the Tentative Order, various parties filed comments objecting to the accounting method utilized by Met-Ed and Penelec.On January 30, 2012, the Commission entered a final order approving Met-Ed's and Penelec's accounting methodology whereby NUG over-collection revenue may be used to reduce non-NUG stranded costs, even if a cumulative NUG stranded cost balance exists.

In the PPUC Order approving the FirstEnergy and Allegheny merger, the PPUC announced that a separate statewide investigation into Pennsylvania's retail electricity market will be conducted with the goal of making recommendations for improvements to ensure that a properly functioning and workable competitive retail electricity market exists in the state. On April 29, 2011, the PPUC entered an Order initiating the investigation and requesting comments from interested parties on eleven directed questions concerning retail markets in Pennsylvania. Met-Ed, Penelec, Penn Power and WP submitted joint comments on June 3, 2011. FES also submitted comments on June 3, 2011. On June 8, 2011, the PPUC conducted an en banc hearing on these issues at which both the Pennsylvania Companies and FES participated and offered testimony.A technical conference was held on August 10, 2011, and a second en banc was held on November 10, 2011, to discuss intermediate steps that can be taken to promote the development of a competitive market. Teleconferences are scheduled through March 2012, with another en banc hearing to be held on March 21, 2012, to explore the future of default service in Pennsylvania following the expiration of the upcoming default service plans on May 31, 2015. Following


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the issuance of a Tentative Order and comments filed by numerous parties, the Commission entered a final order on December 16, 2011, providing recommendations for components to be included in upcoming default service plans. An intermediate work plan was also presented on December 16, 2011, by Tentative Order, on which initial comments were submitted by Met-Ed, Penelec, Penn and WP on January 17, 2012. FES also submitted comments. Reply comments were submitted on February 1, 2012. It is expected that a final order implementing the intermediate work plan and a long range plan will be presented by the PPUC, both in March 2012.

The PPUC issued a Proposed Rulemaking Order on August 25, 2011, which proposed a number of substantial modifications to the current Code of Conduct regulations that were promulgated to provide competitive safeguards to the competitive retail electric market in Pennsylvania. The proposed changes include, but are not limited to: an EGS may not have the same or substantially similar name as the EDC or its corporate parent; EDCs and EGSs would not be permitted to share office space and would need to occupy different buildings; EDCs and affiliated EGSs could not share employees or services, except certain corporate support, emergency, or tariff services (the definition of "corporate support services" excludes items such as information systems, electronic data interchange, strategic management and planning, regulatory services, legal services, or commodities that have been included in regulated rates at less than market value); and an EGS must enter into a trademark agreement with the EDC before using its trademark or service mark. The Proposed Rulemaking Order, which was published on February 11, 2012, calls for comments to be submitted by March 27, 2012. If implemented these rules could require a significant change in the way FES, Met-Ed, Penelec, Penn and WP do business in Pennsylvania, and could possibly have an adverse impact on their results of operations and financial condition.

In November 2011, Met-Ed, Penelec, Penn and WP filed a Joint Petition for Approval of their Default Service Plan for the period June 1, 2013 through May 31, 2015. The Pennsylvania Companies' direct case was submitted in its entirety on December 20, 2011. Evidentiary hearings are scheduled for April 11-13, 2012, and a final order must be entered by the PPUC by August 17, 2012.
West Virginia Regulatory Matters
In 2009, the West Virginia Legislature enacted the AREPA, which generally requires that a specified minimum percentage of electricity sold to retail customers in West Virginia by electric utilities each year be derived from alternative and renewable energy resources according to a predetermined schedule of increasing percentage targets, including10%by 2015,15%by 2020, and25%by 2025. In November 2010, the WVPSC issued RPS Rules, which became effective on January 4, 2011. Under the RPS Rules, on or before January 1, 2011, each electric utility subject to the provisions of this rule was required to prepare an alternative and renewable energy portfolio standard compliance plan and file an application with the WVPSC seeking approval of such plan. MP and PE filed their combined compliance plan in December 2010. A hearing was held at the WVPSC on June 13, 2011. An order was issued by the WVPSC in September 2011, which conditionally approved MP's and PE's compliance plan, contingent on the outcome of the resource credits case discussed below.

Additionally, in January 2011, MP and PE filed an application with the WVPSC seeking to certify three facilities as Qualified Energy Resource Facilities. The application was approved and the three facilities are capable of generating renewable credits which will assist the companies in meeting their combined requirements under the AREPA. An annual update filing is due on March 31, 2012. Further, in February 2011, MP and PE filed a petition with the WVPSC seeking an Order declaring that MP is entitled to all alternative and renewable energy resource credits associated with the electric energy, or energy and capacity, that MP is required to purchase pursuant to electric energy purchase agreements between MP and three non-utility electric generating facilities in West Virginia. The City of New Martinsville and Morgantown Energy Associates, each the owner of one of the contracted resources, has participated in the case in opposition to the Petition. A hearing was held at the WVPSC on August 25 and 26, 2011.On November 22, 2011, the WVPSC issued an order granting ownership of all RECs produced by the facilities to MP. On December 22, 2011, the WVPSC order was appealed, and the order was stayed pending the outcome of the appeal. MP's brief was filed on February 13, 2012. Should MP be unsuccessful in the appeal, it will have to procure the requisite RECs to comply with AREPA from other sources. MP expects to recover such costs from customers.

In September 2011, MP and PE filed with the WVPSC to recover costs associated with fuel and purchased power (the ENEC) in the amount of$32 millionwhich represents an approximate3%overall increase in such costs over the past two years, primarily attributable to rising coal prices. The requested increase was partially offset by$2.5 millionof synergy savings directly resulting from the merger of FirstEnergy and AE, which closed in February 2011. Under a cost recovery clause established by the WVPSC in 2007, MP and PE customer bills are adjusted periodically to reflect upward or downward changes in the cost of fuel and purchased power. The utilities' most recent request to recover costs for fuel and purchased power was in September 2009.MP and PE entered into a Settlement Agreement related to this matter. The WVPSC issued an order on December 30, 2011, approving the settlement agreement. The approved settlement resulted in an increase of$19.6 million, instead of the requested$32 million, with additional costs to be recovered over time with a carrying charge.
FERC Matters

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 on the content of the compliance filings 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’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 at500kV or higher are


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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 than500kV, however, are to be allocated on a load flow methodology, which is generally referred to as a “beneficiary pays” basis. The FERC found that PJM’s current beneficiary-paysapproach to allocating the cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.high voltage transmission facilities.

On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. On February 11, 2008, the FERC’s April 19, 2007, and January 31, 2008, orders wereFERC's Opinion 494 order was appealed to the federalU.S. Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the PUCO and another party have also appealed these orders to the Seventh Circuit, Court of Appeals. The appeals of these parties and others were consolidated for argument in the Seventh Circuit and the Seventh Circuit Court of Appealswhich issued a decision onin August 6, 2009. The court affirmed FERC's ratemaking treatment for existing transmission facilities, but found that FERC had not marshaled enough evidence to supportsupported its decision to allocate costcosts for new 500+500kV and higher voltage facilities on a postage-stampload ratio share basis and, based on this finding, remanded the rate design issue back to FERC. A request for rehearing and rehearing en banc by two companies 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.

In an order dated January 21, 2010, FERC set the matter for a “paper hearings” – meaning that FERC called forhearing” and requested parties to submit comments or written testimonycomments pursuant to the schedule described in the order. FERC identifiednineseparate issues for comments and directed PJM to file the first round of comments on February 22, 2010, with other parties submitting responsive comments and then reply comments on later dates. PJM filed certain studies with FERC on April 8,13, 2010, and May 10, 2010.

The FERC’s orders on PJM rate design preventedin response to the FERC order. PJM's filing demonstrated that 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 abovehigh voltage transmission facilities on a postage-stampbeneficiary pays basis reducesresults in certain load serving entities in PJM bearing 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. On November 14, 2008, PJM submitted revisions to its tariff to incorporate cost responsibility assignments for below 500 kV upgrades included in PJM’s RTEP process in accordance with the settlement. The remaining merchant transmission cost allocation issues were the subject of a hearing at the FERC in May 2008. On November 19, 2009, FERC issued Opinion 503 agreeing that RTEP costs should be allocated on a pro-rata basis to merchant transmission companies. On December 22, 2009, a request for a rehearing of FERC’s Opinion No. 503 was made. On January 19, 2010, the FERC issued a procedural order noting that FERC would address the rehearing requests in a future order.

RTO Consolidation

On August 17, 2009, FirstEnergy filed an application with the FERC requesting to consolidate its transmission assets and operations into PJM. Currently, FirstEnergy’s transmission assets and operations are divided between PJM and MISO. The consolidation would make the transmission assets that are part of ATSI, whose footprint includes the Ohio Companies and Penn, part of PJM. Most of FirstEnergy’s transmission assets in Pennsylvania and allmajority of the transmission assets in New Jersey already operate as a part of PJM. Key elements of the filing include a Fixed Resource Requirement Plan (FRR Plan) that describes the means whereby capacity will be procured and administered as necessary to satisfy the PJM capacity requirements for the 2011-12 and 2012-13 delivery years; and also a request that ATSI’s transmission customers be excused from the costs for regional transmission projects that were approved through PJM’s RTEP process prior to ATSI’s entry into PJM (legacy RTEP costs). The integration is expected to be completecosts. Numerous parties filed responsive comments or studies on June 1, 2011, to coincide with delivery of power under the next competitive generation procurement process for the Ohio Companies and Penn. To ensure a definitive ruling at the same time the FERC rules on its request to integrate ATSI into PJM, on October 19, 2009, FirstEnergy filed a related complaint with the FERC on the issue of exempting the ATSI footprint from the legacy RTEP costs.

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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,May 28, 2010 and reply comments on October 13, 2009,June 28, 2010. FirstEnergy and attended a public meetingnumber of other utilities, industrial customers and state commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. Other utilities and state commissions supported continued socialization of these costs on September 15, 2009 to answer questions regardinga load ratio share basis. This matter is awaiting action by FERC. FirstEnergy cannot predict the outcome of this matter or estimate the possible loss or range of loss.

RTO consolidation. Several parties have intervenedRealignment

On June 1, 2011, ATSI and the ATSI zone entered into PJM. The move was performed as planned with no known operational or reliability issues for ATSI or for the wholesale transmission customers in the regulatory dockets atATSI zone.

On February 1, 2011, ATSI in conjunction with PJM filed its proposal with FERC for moving its transmission rate into PJM's tariffs. On April 1, 2011, the FERCMISO TOs (including ATSI) filed proposed tariff language that describes the mechanics of collecting and atadministering MTEP costs from ATSI-zone ratepayers. From March 20, 2011 through April 1, 2011, FirstEnergy, PJM and the PUCO. Certain interveners have commented and protested particular elementsMISO submitted numerous filings for the purpose of effecting movement of the ATSI zone to PJM on June 1, 2011. These filings include amendments to the MISO's tariffs (to remove the ATSI zone), submission of load and generation interconnection agreements to reflect the move into PJM, and submission of changes to PJM's tariffs to support the move into PJM.

On May 31, 2011, FERC issued orders that address the proposed RTO consolidation, includingATSI transmission rate, and certain parts of the MISO tariffs that reflect the mechanics of transmission cost allocation and collection. In its May 31, 2011 orders, FERC approved ATSI's proposal to move the ATSI formula rate into the PJM tariff without significant change. Speaking to ATSI's proposed treatment of the MISO's exit fees and charges for transmission costs that were allocated to the ATSI zone, FERC required ATSI to present a cost-benefit study that demonstrates that the benefits of the move for transmission customers exceed the costs of any such move, which FERC had not previously required. Accordingly, FERC ruled that these costs must be removed from ATSI's proposed transmission rates until such time as ATSI files and FERC approves the cost-benefit study. On June 30, 2011, ATSI submitted the compliance filing that removed the MISO exit fees and transmission cost allocation charges from ATSI's proposed transmission rates. Also on June 30, 2011, ATSI requested rehearing of FERC's decision to require a cost-benefit analysis as part of FERC's evaluation of ATSI's proposed transmission rates. Finally, and also on June 30, 2011, the MISO and the MISO TOs filed a competing compliance filing - one that would require ATSI to pay certain charges related to construction and operation of transmission projects within the MISO even though FERC ruled that ATSI cannot pass these costs on to ATSI's customers. ATSI on the one hand, and the MISO and MISO TOs on the other, have submitted subsequent filings - each of which is intended to refute the other's claims. ATSI's compliance filing and request for rehearing, as well as the pleadings that reflect the dispute between ATSI and the MISO/MISO TOs, are currently pending before FERC.

From late April 2011 through June 2011, FERC issued other orders that address ATSI's move into PJM. Also, ATSI and the MISO were able to negotiate an exit feeagreement of ATSI's responsibility for certain charges associated with long term firm transmission rights that, according to the MISO, were payable by the ATSI zone upon its departure from the MISO. ATSI did not and does not agree that these costs should be charged to ATSI but, in order to settle the case and all claims associated with the case, ATSI agreed to a one-time payment of$1.8 millionto the MISO. This settlement agreement has been submitted for FERC's review and approval. The final outcome of those proceedings that address the remaining open issues related to ATSI's move into PJM and their impact, if any, on FirstEnergy cannot be predicted at this time.

MISO Multi-Value Project Rule Proposal

In July 2010, MISO and certain MISO transmission owners jointly filed with FERC their proposed cost allocation methodology for certain new transmission projects. The new transmission projects--described as MVPs - are a class of transmission projects that are approved via the MTEP. The filing parties proposed to allocate the costs of MVPs by means of a usage-based charge that will be applied to all loads within the MISO footprint, and to energy transactions that call for power to be “wheeled through” the MISO as well as to energy transactions that “source” in the MISO but “sink” outside of MISO. The filing parties expect that the MVP proposal will fund the costs of large transmission projects designed to bring wind generation from the upper Midwest to load centers


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in the east. The filing parties requested an effective date for the proposal of July 16, 2011. On August 19, 2010, MISO's Board approved the first MVP project -- the “Michigan Thumb Project.” Under MISO's proposal, the costs of MVP projects approved by MISO's Board prior to the June 1, 2011 effective date of FirstEnergy's integration into PJM would continue to be allocated to FirstEnergy. MISO estimated that approximately$15 millionin annual revenue requirements would be allocated to the ATSI zone associated with the Michigan Thumb Project upon its completion.

In September 2010, FirstEnergy filed a protest to the MVP proposal arguing that MISO's proposal to allocate costs of MVPs projects across the entire MISO footprint does not align with the established rule that cost allocation is to be based on cost causation (the “beneficiary pays” approach). FirstEnergy also argued that, in light of progress that had been made to date in the ATSI integration into PJM, it would be unjust and unreasonable to allocate any MVP costs to PJM, and cost-allocations of future transmission upgrades in PJM and MISO.the ATSI zone, or to ATSI. Numerous other parties filed pleadings on MISO's MVP proposal.

OnIn December 17, 2009,2010, FERC issued an order approving subjectthe MVP proposal without significant change. Despite being presented with the issue by FirstEnergy and the MISO, the FERC did not address clearly the question of whether the MVP costs would be payable by ATSI or load in the ATSI zone. FERC stated that the MISO's tariffs obligate ATSI to certain future compliance filings, ATSI’s movepay all charges that attached prior to PJM. FirstEnergy’s requestATSI's exit but ruled that the question of the amount of costs that are to be exempted from legacy RTEP costs was rejectedallocated to ATSI or to load in the ATSI zone were beyond the scope of FERC's order and its complaint dismissed.would be addressed in future proceedings.

On December 17, 2009,January 18, 2011, FirstEnergy requested rehearing of FERC's order. In its rehearing request, FirstEnergy argued that because the MVP rate is usage-based, costs could not be applied to ATSI, executedwhich is a stand-alone transmission company that does not use the PJM Consolidated Transmission Owners Agreement. On December 18, 2009, the Ohio Companies and Penn executed the PJM Operating Agreementtransmission system. FirstEnergy also renewed its arguments regarding cost causation and the PJM Reliability Assurance Agreement. Executionimpropriety of allocating costs to the ATSI zone or to ATSI.On October 21, 2011, FERC issued its order on rehearing, but that order did not address FirstEnergy's argument directly. FERC ruled instead that if ATSI was subject to MVP charges then ATSI owed these agreements committed ATSIcharges upon exit of the MISO. On October 31, 2011, FESC filed a Petition of Review for the FERC's December 2010 order and October 21, 2011 order on rehearing of that order with the Ohio CompaniesU.S. Court of Appeals for the D.C. Circuit. Other parties also filed appeals of those orders and, Penn’s load to moving into PJM onin November, 2011, the schedule describedcases were consolidated for briefing and disposition in the application and approved inU.S. Court of Appeals for the Seventh Circuit. On January 27, 2012, the court ordered the FERC Order (June 1, 2011).to file a proposed briefing format and schedule on or before March 20, 2012.

On August 3, 2011, FirstEnergy filed a complaint with FERC based on the FERC's December 2010 order. In the complaint, FirstEnergy argued that ATSI perfected the legal and financial requirements necessary to exit MISO before any MVP responsibilities could attach and asked FERC to rule that MISO cannot charge ATSI for MVP costs. On September 2, 2011, MISO, its TOs and other parties, filed responsive pleadings. On September 19, 2011, ATSI filed an answer. On December 29, 2011, the MISO and the MISO TOs filed a new “Schedule 39” to the MISO's tariff. Schedule 39 purports to establish a process whereby the MISO would bill TOs for MVP costs that, according to the MISO, attached to the utility prior to such TOs withdrawal from the MISO. On January 15,19, 2012, FirstEnergy filed a protest to the MISO's new Schedule 39 tariff.

On February 27, 2012, FERC issued an order (February 2012 Order) dismissing ATSI's August 3, 2011 complaint. In the February 2012 Order, FERC accepted the MISO's Schedule 39 tariff, subject to hearings and potential refund of MVP charges to ATSI. The basis for any subsequent hearing is whether the Schedule 39 tariff was in effect at the time that ATSI exited the MISO. FirstEnergy is evaluating the February 2012 Order and will determine the next steps.

FirstEnergy cannot predict the outcome of these proceedings or estimate the possible loss or range of loss.

FirstEnergy Companies' PJM FTR Contract Underfunding Complaint

On December 28, 2011, FES and AE Supply filed a complaint with FERC against PJM challenging the ongoing underfunding of FTR contracts, which exist to hedge against transmission congestion in the day-ahead markets. The underfunding is a result of PJM's practice of using the funds that are intended to pay the holders of FTR contracts to pay instead for congestion costs that occur in the real time markets. Underfunding of the FTR contracts resulted in losses of approximately$35 millionto FES and AE Supply in the 2010-2011 Delivery Year. To date, losses for the 2011-2012 Delivery Year are estimated to be approximately$6 million.

On January 13, 2012, PJM filed comments that describe changes to the PJM tariff that, if adopted, should remedy the underfunding issue. Many parties also filed comments supporting FES' and AE Supply's position. Other parties, generally representatives of end-use customers who will have to pay the charges, filed in opposition to the complaint. The matter is currently pending before FERC. FirstEnergy cannot predict the outcome of this matter or estimate the possible loss or range of loss.
California Claims Matters

In October 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the CDWR during 2001. The settlement proposal claims that CDWR is owed approximately$190 millionfor these alleged overcharges. This proposal was made in the context of mediation efforts by FERC and the United States Court of Appeals for the Ninth Circuit in pending proceedings to resolve all outstanding refund and other claims, including claims of alleged price manipulation in the California energy markets during 2000 and 2001. The Ninth Circuit has since remandedoneof those proceedings to FERC, which arises out of claims previously filed with FERC by the California Attorney General on behalf of certain California parties against various sellers


11


in the California wholesale power market, including AE Supply (the Lockyer case). AE Supply and several other sellers filed motions to dismiss the Lockyer case. In March 2010, the Ohio Companiesjudge assigned to the case entered an opinion that granted the motions to dismiss filed by AE Supply and Penn submitted a compliance filing describingother sellers and dismissed the process whereby ATSI-zone load serving entities (LSEs) can “opt out”claims of the Ohio Companies' and Penn's FRR Plan forCalifornia Parties. On May 4, 2011, FERC affirmed the 2011-12 and 2012-13 Delivery Years.judge's ruling. On January 16, 2010, FirstEnergy filed for clarification orJune 3, 2011, the California parties requested rehearing of the May 4, 2011 order. The request for rehearing remains pending.

In June 2009, the California Attorney General, on behalf of certain issues associatedCalifornia parties, filed a second complaint with implementingFERC against various sellers, including AE Supply (the Brown case), again seeking refunds for trades in the FRR auctionsCalifornia energy markets during 2000 and 2001. The above-noted trades with CDWR are the basis for including AE Supply in this new complaint. AE Supply filed a motion to dismiss the Brown complaint that was granted by FERC on May 24, 2011. On June 23, 2011, the California Attorney General requested rehearing of the May 24, 2011 order. That request for rehearing also remains pending. FirstEnergy cannot predict the outcome of either of the above matters or estimate the possible loss or range of loss.

PATH Transmission Project

The PATH Project is comprised of a765kV transmission line that was proposed to extend from West Virginia through Virginia and into Maryland, modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland.

PJM initially authorized construction of the PATH Project in June 2007. In December 2010, PJM advised that its 2011 Load Forecast Report included load projections that are different from previous forecasts and that may have an impact on the proposed schedule. Onin-service date for the PATH Project. As part of its 2011 RTEP, and in response to a January 19, 2010,2011, directive by a Virginia Hearing Examiner, PJM conducted a series of analyses using the most current economic forecasts and demand response commitments, as well as potential new generation resources. Preliminary analysis revealed the expected reliability violations that necessitated the PATH Project had moved several years into the future. Based on those results, PJM announced on February 28, 2011, that its Board of Managers had decided to hold the PATH Project in abeyance in its 2011 RTEP and directed FirstEnergy and AEP, as the sponsoring transmission owners, to suspend current development efforts on the project, subject to those activities necessary to maintain the project in its current state, while PJM conducts more rigorous analysis of the need for the project as part of its continuing RTEP process. PJM stated that its action did not constitute a directive to FirstEnergy and AEP to cancel or abandon the PATH Project. PJM further stated that it will complete a more rigorous analysis of the PATH Project and other transmission requirements and its Board will review this comprehensive analysis as part of its consideration of the 2011 RTEP. On February 28, 2011, affiliates of FirstEnergy and AEP filed motions or notices to withdraw applications for rehearing of FERC’s decisionauthorization to imposeconstruct the legacy RTEP costs on ATSI’s transmission customers. Also on Januaryproject that were pending before state commissions in West Virginia, Virginia and Maryland. Withdrawal was deemed effective upon filing the notice with the MDPSC. The WVPSC and VSCC have granted the motions to withdraw.

PATH submitted a filing to FERC to implement a formula rate tariff effective March 1, 2008. In a November 19, 2010 several parties, includingorder addressing various matters relating to the PUCOformula rate, FERC set the project's base ROE for hearing and reaffirmed its prior authorization of a return on CWIP, recovery of start-up costs and recovery of abandonment costs. In the order, FERC also granted a1.5%ROE incentive adder and a0.5%ROE adder for RTO participation. These adders will be applied to the base ROE determined as a result of the hearing. The PATH Companies, Joint Intervenors, Joint Consumer Advocates and FERC staff have agreed to a four year moratorium. A settlement was reached, which reflects a base ROE of10.4%(plus authorized adders) effective January 1, 2011. Accordingly, the revised ROE was reflected in a revised Projected Transmission Revenue Requirement for 2011 with true-up occurring in 2013. The FirstEnergy portion of the refund for March 1, 2008, through December 31, 2010, is approximately$2 million(inclusive of interest). The refund amount was computed using a base ROE of10.8%plus authorized adders. On October 7, 2011, PATH and six intervenors submitted to FERC an unopposed settlement agreement. Contemporaneous with this submission, PATH and the OCC askedsix intervenors filed with the Chief ALJ of FERC a joint motion for rehearinginterim approval and authorization to implement the refund on an interim basis pending issuance of parts of FERC’s order. None ofa FERC order acting on the rehearing parties asked FERCsettlement agreement. On October 12, 2011, the motion for interim approval and authorization to rescind authorization for ATSI to enter PJM. Instead, parties focused on questions of cost and cost allocation or on alleged errors in implementingimplement the move.  On February 3, 2010, FirstEnergy filed an answer torefund was granted by the January 19, 2010 rehearing request of other parties.Chief ALJ. On February 16, 2010, FirstEnergy submitted a second compliance filing to FERC;2012, FERC approved the filing describes communications protocolssettlement agreement and performance deficiency penalties for capacity suppliers that are takendismissed as moot, in FRR auctions.

FirstEnergy will conduct FRR auctions on March 15-19, 2010, for the 2011-12 and 2012-13 delivery years. LSE’s in the ATSI territory, including the Ohio Companies and Penn, will participate in PJM’s next base residual auction for capacity resources for the 2013-2014 delivery years. This auction will be conducted in Maylight of 2010. FirstEnergy expects to integrate into PJM effective June 1, 2011.

Changes ordered for PJM Reliability Pricing Model (RPM) Auction

On May 30, 2008, a group of PJM load-serving entities, state commissions, consumer advocates, and trade associations (referred to collectively as the RPM Buyers) filed a complaint at the FERC against PJM alleging that threeits approval of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the Federal Power Act. On September 19, 2008, the FERC denied the RPM Buyers’ complaint. 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. ThePATH's pending request for settlement hearings was granted. Settlement had not been reached by January 9, 2009 and, accordingly, FirstEnergy and other parties submitted comments on PJM’s proposed tariff amendments. On January 15, 2009, the Chief Judge issued an order terminating settlement discussions. On February 9, 2009, PJM and a group of stakeholders submitted an offer of settlement, which used the PJM December 12, 2008 filing as its starting point, and stated that unless otherwise specified, provisions filed by PJM on December 12, 2008 apply.

On March 26, 2009, the FERC accepted in part, and rejected in part, tariff provisions submitted by PJM, revising certain parts of its RPM. It ordered changes included making incremental improvements to RPM and 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; 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 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. On December 1, 2009, PJM informed FERC that PJM would file a scarcity-pricing design with the FERC on April 1, 2010.

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MISO-PJM Billing Dispute

In September 2009, PJM reported that it had discovered a modeling error in the market-to-market power flow calculations between PJM and the MISO under the Joint Operating Agreement. The error, which dates back to 2005, was a result of the incorrect modeling of certain generation resources that have an impact on power flows across the PJM-MISO border. FERC settlement discussions on this issue have commenced, and FirstEnergy is participating in these discussions. The next settlement conference is set for February 25, 2010.  Although the amount of the error is subject to dispute, PJM has estimated the magnitude of the error to be approximately $77 million in total to all parties. Should a payment by PJM to the MISO relating to the modeling error be required, the method by which PJM would collect such payments from PJM participants, and how MISO would allocate payments received to MISO participants, is uncertain at this time.

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. The FERC conditionally approved MISO’s Resource Adequacy proposal on March 26, 2008. 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 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 program was implemented as planned and became effective on June 1, 2009, the beginning of the MISO planning year. On June 17, 2009, MISO submitted a compliance filing in response to the FERC’s April 16, 2009 order directing it to address, among others, various market monitoring and mitigation issues. On July 8, 2009, various parties submitted comments on and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific aspects of the MISO’s and Independent Market Monitor’s proposals for market monitoring and mitigation and other issues that it believes the FERC should address and clarify. On October 23, 2009, FERC issued an order approving a MISO compliance filing that revised its tariff to provide for netting of demand resources, but prohibiting the netting of behind-the-meter generation.

FES Sales to Affiliates

FES supplied all of the power requirements for the Ohio Companies pursuant to a PSA 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. Rehearing was denied on July 31, 2009. On October 19, 2009, the FERC accepted FirstEnergy’s revised tariffs.

On May 13-14, 2009, FES participated in a descending clock auction for PLR service administered by the Ohio Companies and their consultant, CRA International. FES won 51 tranches in the auction, and entered into a Master SSO Supply Agreement to provide capacity, energy, ancillary services and transmission to the Ohio Companies for a two-year period beginning June 1, 2009.  Other winning suppliers have assigned their Master SSO Supply Agreements to FES, five of which were effective in June, two more in July, four more in August and ten more in September, 2009.  FES also supplies power used by Constellation to serve an additional five tranches.  As a result of these arrangements, FES serves 77 tranches, or 77% of the PLR load of the Ohio Companies.

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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 (PRA) continues to limit the amount of capacity resources required to be supplied by FES to 3,544 MW, but requires FES to supply essentially all of Met-Ed, Penelec, and Waverly’s energy requirements in 2010. Under the Fourth Restated Partial Requirements Agreement, Met-Ed, Penelec, and Waverly (Buyers) assigned 1,300 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 under the Fourth Restated Partial Requirements Agreement 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, respectively, 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.order.

The Yards Creek Pumped Storage Project is a 400 MW hydroelectric project located in Warren County, New Jersey.  JCP&L owns an undivided 50% interest in the project, and JCP&L operates the project. PSEG Fossil, LLC, a subsidiary of Public Service Enterprise Group, owns the remaining interest in the plant. The project was constructed in the early 1960s, and became operational in 1965.  Authorization to operate the project is by a license issued by the FERC.  The existing license expires on February 28, 2013.

FirstEnergy and PSEG desire to renew the license and, to that end, on January 11, 2008, JCP&L and PSEG Fossil submitted the initial documents necessary to obtain a new license for the project.  The process for relicensing (renewing the license for) a hydroelectric project is described in FERC’s Integrated Licensing Process (ILP) regulations.  The ILP regulations call for numerous environmental, operational, structural and safety and other studies to be conducted as part of the relicensing process.  Although some of these studies were initiated in 2009, the bulk of the studies will be performed in 2010 – all for the purpose of submitting the application for a new license on February 28, 2011.  The ILP regulations provide for opportunity for public notice and comment as part of many of these study processes; meaning that federal and state regulatory agencies, as well as members of the public, will have amply opportunity to participate in the relicensing process.  The ILP regulations provide significant discretion for FERC to set a procedural schedule to act on the license application; meaning that FirstEnergy is not able at this time to predict when FERC will take final action in issuing the new license for the Yards Creek project.  To the extent, however that the license proceedings extend beyond the February 28, 2013 expiration date for the current license, the current license will be extended as necessary to permit FERC to issue the new license.

Capital Requirements

Our capital spending for 2010 is expected to be approximately $1.65 billion (excluding nuclear fuel), of which $241 million relates to Sammis AQC system expenditures. Capital spending for 2011 and 2012 is expected to be approximately $1.0$2.1 billion(excluding nuclear fuel).For 2013, we anticipate baseline capital expenditures of approximately $2.0 billion, which exclude any potential additional strategic opportunities, future mandated spending, energy efficiency or environmental spending relating to $1.2 billion each year. MATS. Planned capital initiatives are intended to promote reliability, improve operations, and support current environmental and energy efficiency directives.Our capital investments for additional nuclear fuel during 2010 are estimatedexpected to be approximately $203 million.

$280 million and $219 million in 2012 and 2013, respectively.
Anticipated capital expenditures for the Utilities, FES and FirstEnergy’s other subsidiaries for 2010,2012, excluding nuclear fuel, are shown in the following table. Such costs include expenditures for the betterment of existing facilities and for the construction of generating capacity, facilities for environmental compliance, transmission lines, distribution lines and substations, and other assets.


  2009  
Capital
Expenditures
Forecast
 
  
Actual(1)
  2010 
  (In millions) 
OE $131  $116 
Penn  23   19 
CEI  111   108 
TE  46   48 
JCP&L  171   170 
Met-Ed  100   102 
Penelec  132   127 
ATSI  34   49 
FGCO  724   592 
NGC  242   254 
Other subsidiaries  56   66 
Total $1,770  $1,651 
         
(1) Excludes nuclear fuel.
 
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13
 
2011
Actual
 
Capital
Expenditures
Forecast 2012
 (In millions)
OE$178
 $167
Penn30
 21
CEI120
 110
TE47
 39
JCP&L327
 206
Met-Ed138
 105
Penelec159
 136
MP164
 142
PE96
 89
WP153
 128
ATSI113
 84
TrAIL82
 20
FGCO198
 131
NGC409
 452
AE Supply141
 144
Other subsidiaries128
 116
Total$2,483
 $2,090
During the 2010-20142012-2016 period, maturities of, and sinking fund requirements for long-term debt of FirstEnergy and its subsidiaries are:

 2012 2013-2016 Total
 (In millions)
FE$—
 $150
 $150
FES270
 1,758
 2,028
OE—
 400
 400
Penn1
 4
 5
CEI22
 381
 403
JCP&L34
 458
 492
Met-Ed—
 429
 429
Penelec—
 195
 195
Other(1)
637
 1,631
 2,268
Total$964
 $5,406
 $6,370
  Long-Term Debt Redemption Schedule 
  2010   2011-2014  Total 
  (In millions) 
FirstEnergy $1  $256  $257 
FES  52   300   352 
OE  1   -   1 
Penn  1   5   6 
CEI(1)
  -   300   300 
JCP&L  31   140   171 
Met-Ed  100   400   500 
Penelec  24   150   174 
Other(2)
  58   (28)  30 
Total $268  $1,523  $1,791 
             
(1) CEI has an additional $110 million due to associated companies in 2010-2014.
 
(2) Includes elimination of certain intercompany debt.
 

(1)
Includes debt of AE and its subsidiaries and the elimination of certain intercompany debt.
The following table displaystables display consolidated operating lease commitments netas of capital trust cash receipts for the 2010-2014 period.December 31, 2011.
  FirstEnergy  
Operating Leases Lease Payments 
Capital Trust(1)
 Net
  (In millions)
2012 $383
 $125
 $258
2013 382
 130
 252
2014 371
 131
 240
2015 373
 90
 283
2016 344
 29
 315
Years thereafter 1,803
 4
 1,799
Total minimum lease payments $3,656
 $509
 $3,147
(1)
PNBV and Shippingport purchased a portion of the lease obligation bonds associated with certain sale and leaseback transactions. These arrangements effectively reduce lease costs related to those transactions.



  Net Operating Lease Commitments 
  2010   2011-2014  Total 
  (In millions) 
           
OE $104  $403  $507 
CEI(1)
  (40)  (194)  (234)
TE  35   138   173 
JCP&L  6   19   25 
Met-Ed  7   13   20 
Penelec  3   9   12 
FESC  14   39   53 
FGCO  199   888   1,087 
NGC(2)
  (103)  (414)  (517)
Total $225  $901  $1,126 
             
(1) Reflects CEI's investment in Shippingport that purchased lease obligations bonds issued on behalf of lessors in Bruce Mansfield Units 1, 2 and 3 sale and leaseback transactions. Effective October 16, 2007, CEI and TE assigned their leasehold interests in the Bruce Mansfield Plant to FGCO.
 
(2) Reflects NGC’s purchase of lessor equity interests in Beaver Valley Unit 2 and Perry in the second quarter of 2008.
 
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Operating Leases FES 
OE(1)
 CEI 
TE(1)
 JCP&L Met-Ed Penelec
  (In millions)
2012 $237
 $147
 $4
 $64
 $7
 $4
 $3
2013 241
 146
 3
 64
 7
 4
 3
2014 236
 145
 3
 64
 6
 3
 2
2015 239
 145
 2
 64
 5
 4
 2
2016 230
 117
 3
 64
 5
 3
 2
Years thereafter 1,662
 49
 4
 14
 48
 37
 12
Total minimum lease payments $2,845
 $749
 $19
 $334
 $78
 $55
 $24
(1)
Includes certain minimum lease payments associated with NGC's lessor equity interests in Perry and Beaver Valley Unit 2 that are eliminated in consolidation (see Note 6, Leases, of the Combined Notes to the Consolidated Financial Statements).
FirstEnergy expects its existing sources of liquidity to remain sufficient to meet its anticipated obligations and those of its subsidiaries. FirstEnergy and its subsidiaries'FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. During 2009In addition to internal sources to fund liquidity and in subsequent years,capital requirements for 2012 and beyond, FirstEnergy expects to satisfy theserely on external sources of funds. Short-term cash requirements with a combination ofnot met by cash provided from operations and funds from the capital markets.are generally satisfied through short-term borrowings. Long-term cash needs may be met through issuances of debt and/or equity securities. FirstEnergy also expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements during those periods.along with continued access to long-term capital markets.

FirstEnergy had approximately $1.2 billion of no significant short-term indebtednessdebt outstanding as of December 31, 2009, comprised of $1.1 billion in borrowings under the $2.75 billion revolving line of credit described below, $100 million of other bank borrowings and $31 million of currently payable notes.2011. Total short-term bank lines of committed credit to FirstEnergy FES and the Utilitiestotaled $5.0 billion. FirstEnergy’s available liquidity as of January 31, 2010 were approximately $3.4 billion.2012, was as follows:

Company Type Maturity Commitment Available Liquidity
      (In millions)
FirstEnergy(1)
 Revolving June 2016 $2,000
 $1,395
FES / AE Supply Revolving June 2016 2,500
 2,498
TrAIL Revolving Jan. 2013 450
 450
AGC Revolving Dec. 2013 50
 —
    Subtotal $5,000
 $4,343
    Cash —
 49
    Total $5,000
 $4,392
(1)
FE and the Utilities
FirstEnergy along withand certain of its subsidiaries are party to a $2.75 billionparticipate in two five-year syndicated revolving credit facility. FirstEnergy has the abilityfacilities with aggregate commitments of$4.5 billion(Facilities).
An aggregate amount of$2 billionis available to request an increase in the total commitments availablebe borrowed under thisa syndicated revolving credit facility up to a maximum of $3.25 billion,(FirstEnergy Facility), subject to separate borrowing sublimits for each borrower. The borrowers under the discretion ofFirstEnergy Facility are FE, OE, Penn, CEI, TE, Met-Ed, ATSI, JCP&L, MP, Penelec, PE and WP. An additional$2.5 billionis available to be borrowed by FES and AE Supply under a separate syndicated revolving credit facility (FES/AE Supply Facility), subject to separate borrowing sublimits for each lender to provide additional commitments. borrower.
Commitments under each of the facility areFacilities will be available until August 24, 2012,June 17, 2016, unless the lenders agree, at the request of the applicable borrowers, to an unlimited number ofup to two additional one-year extensions. Generally, borrowings under each of the facility must be repaid within 364 days. Available amounts forFacilities are available to each borrower separately and mature on the earlier of364days from the date of borrowing or the commitment termination date, as the same may be extended.
Borrowings under each of the Facilities are subject to the usual and customary provisions for acceleration upon the occurrence of events of default, including a specified sub-limit,cross-default for other indebtedness in excess of$100 million, as well as applicable regulatory and other limitations. The annual facility fee is 0.125%.described further in Note 12, Capitalization.

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As FirstEnergy also has established$500 millionof January 31, 2010, FES had a $100 million bank credit facility in addition to a $1 billion credit limit associated with FirstEnergy's $2.75 billion revolving credit facility. Also, an aggregate of $515 million of accounts receivable financing facilities through the Ohiothat are available to TrAIL ($450 million) and Pennsylvania Companies may be accessed to meet working capital requirementsAGC($50 million) until January 2013 and for other general corporate purposes. FirstEnergy's available liquidity as of January 31, 2010, is described in the following table.December 2013, respectively.

Company Type Maturity Commitment  
Available
Liquidity as of
January 31, 2010
 
      (In millions) 
FirstEnergy(1)
 Revolving Aug. 2012 $2,750  $1,387 
FirstEnergy Solutions Bank line Mar. 2011  100   - 
Ohio and Pennsylvania Companies Receivables financing 
Various(2)
  515   308 
    Subtotal $3,365  $1,695 
    Cash  -   764 
    Total $3,365  $2,459 

(1)FirstEnergy Corp. and subsidiary borrowers.
(2)$370 million expires February 22, 2010; $145 million expires December 17, 2010. The Ohio and Pennsylvania Companies have typically renewed expiring receivables facilities on an annual basis and expect to continue that practice as market conditions and the continued quality of receivables permit.

FirstEnergy'sFE’s primary source of cash for continuing operations as a holding company is cash from the operations of its subsidiaries. During 2009, the holding company2011, FirstEnergy received $972 million$1.8 billion of cash dividends on common stock from its subsidiaries and paid $670$881 millionin cash dividends to common shareholders, including $20 million paid in March by AE to its former shareholders.


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As ofDecember 31, 2009,2011, the Ohio Companies and Penn had the aggregate capability to issue approximately $1.4$2.7 billionof 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 $127$232 millionand $36$20 million, respectively, as of December 31, 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.respectively. As a result of the indenture provisions, for TE tocannot incur any additional secured debt do not apply. In August 2009 CEI issued $300 million of FMBs. CEI restricted $150 million of the proceeds to fund the redemption of $150 million of secured notes that were paid in November 2009. Based upon FGCO's FMB indenture, net earnings and available bondable property additions as of December 31, 2009, FGCO had the capability to issue $2.2 billion of additional FMBs under the terms of that indenture.debt. Met-Ed and Penelec had the capability to issue secured debt of approximately $379$376 millionand $319$382 million, respectively, under provisions of their senior note indentures as ofDecember 31, 2009.2011. In addition, based upon their respective FMB indentures, net earnings and available bondable property additions as ofDecember 31, 2011, MP, PE and WP had the capability to issue approximately$1.1 billionof additional FMBs in the aggregate. These companies may be further limited by the financial covenants of the Facilities and subject to current regulatory approvals and applicable statutory and/or charter limitations.
Based upon FGCO’s net earnings and available bondable property additions under its FMB indentures as ofDecember 31, 2011, FGCO had the capability to issue$2.1 billionof additional FMBs under the terms of that indenture. Based upon NGC’s net earnings and available bondable property additions under its FMB indenture as ofDecember 31, 2011, NGC had the capability to issue$2.0 billionof additional FMBs under the terms of that indenture.
To the extent that coverage requirements or market conditions restrict the subsidiaries’ abilities to issue desired amounts of FMBs or preferred stock, they may seek other methods of financing. Such financings could include the sale of preferred and/or preference stock or of such other types of securities as might be authorized by applicable regulatory authorities which would not otherwise be sold andsold. These financings could result in annual interest charges and/or dividend requirements in excess of those that would otherwise be incurred.

On September 22, 2008, 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 may utilize the shelf registration statement to offer and sell unsecured, and in some cases, secured debt securities.

Nuclear Operating Licenses

In August 2007,2010, FENOC submitted an application to the NRC to renewfor renewal of the Davis-Besse operating licenses for the Beaver Valley Power Station (Units 1 and 2)license for an additional 20 years.twenty years, until 2037. By an order dated April 26, 2011, a NRC ASLB granted a hearing on the Davis-Besse license renewal application to a group of petitioners. By this order, the ASLB also admitted two contentions challenging whether FENOC's Environmental Report adequately evaluated (1) a combination of renewable energy sources as alternatives to the renewal of Davis-Besse's operating license, and (2) severe accident mitigation alternatives at Davis-Besse. On November 5, 2009,May 6, 2011, FENOC filed an appeal with the NRC issuedfrom the order granting a renewed operatinghearing on the Davis-Besse license renewal application.On January 10, 2012, intervenors petitioned the ASLB 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.

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Eacha new contention on the cracking of the nuclear units in the FES portfolio operates under a 40-year operating license granted by the NRC. Davis-Besse shield building discussed below.
The following table summarizes the current operating license expiration dates for FES’FES' nuclear facilities in service.

Station In-Service Date Current License Expiration
Beaver Valley Unit 1 1976 2036
Beaver Valley Unit 2 1987 2047
Perry 1986 2026
Davis-Besse 1977 2017

Nuclear Regulation

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As ofDecember 31, 2009,2011, FirstEnergy had approximately $1.9$2 billioninvested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy provided an additional $80 million parental guarantee associated with the funding of decommissioning costs for these units and indicated that it planned to contribute an additional $80 million to these trusts by 2010. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy’s nuclear decommissioning trustsFirstEnergy's NDT fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy’sFirstEnergy's obligation to fund the trusts may increase. Disruptions in the capital markets and itstheir effects on particular businesses and the economy in generalcould also affectsaffect the values of the NDT. On March 28, 2011, FENOC submitted its biennial report on nuclear decommissioning trusts. On June 18, 2009,funding to the NRC informed FENOC that its review tentatively concluded thatNRC. This submittal identified a total shortfall existed in the decommissioning trust fund for Beaver Valley Unit 1. On November 24, 2009, FENOC submitted a revisednuclear decommissioning funding calculation using the NRC formula method based on the renewed license for Beaver Valley Unit 1 and Perry of approximately$92.5 million. By letter dated December 29, 2011, FENOC informed the NRC staff that it had increased the parental guarantee to$95 million.
In January 2004, subsidiaries of FirstEnergy filed a lawsuit in the U.S. Court of Federal Claims seeking damages in connection with costs incurred at the Beaver Valley, Davis-Besse and Perry nuclear facilities as a result of the DOE's failure to begin accepting spent nuclear fuel on January 31, 1998. DOE was required to begin accepting spent nuclear fuel by the Nuclear Waste Policy Act (42 USC 10101 et seq) and the contracts entered into by the DOE and the owners and operators of these facilities pursuant to the Act.In January 2012, the applicable FirstEnergy affiliates reached a$48 millionsettlement of these claims.
On October 1, 2011, Davis-Besse was safely shut down for a scheduled outage to install a new reactor vessel head and complete other maintenance activities. The new reactor head, which extended operations until 2036. FENOC’s submittal demonstrated that therereplaced a head installed in 2002, enhances safety and reliability, and features control rod nozzles made of material less susceptible to cracking. On October 10, 2011, following opening of the building


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for installation of the new reactor head, a sub-surface hairline crack was a de minimis shortfall. identified in one of the exterior architectural elements on the shield building. These elements serve as architectural features and do not have structural significance. During investigation of the crack at the shield building opening, concrete samples and electronic testing found similar sub-surface hairline cracks in most of the building's architectural elements. FENOC's investigation also identified other indications. Included among them were sub-surface hairline cracks in the upper portion of the shield building (above elevation 780') and in the vicinity of the main steam line penetrations.A team of industry-recognized structural concrete experts and Davis-Besse engineers has determined these conditions do not affect the facility's structural integrity or safety.
On December 2, 2011, the NRC issued a CAL which concluded that FENOC provided "reasonable assurance that the shield building remains capable of performing its safety functions." The CAL imposed a number of commitments from FENOC including, submitting a root cause evaluation and corrective actions to the NRC by February 28, 2012, and further evaluations of the shield building. On February 27, 2012, FENOC sent the root cause evaluation to the NRC. Finally, the CAL also stated that the NRC was still evaluating whether the current condition of the shield building conforms to the plant's licensing basis. On December 6, 2011, the Davis-Besse plant returned to service.
By letter dated August 25, 2011, the NRC made a final significance determination (white) associated with a violation that occurred during the retraction of a source range monitor from the Perry reactor vessel. The NRC also placed Perry in the degraded cornerstone column (Column 3) of the NRC's Action Matrix governing the oversight of commercial nuclear reactors. As a result, the NRC staff will conduct several supplemental inspections, culminating in an inspection using Inspection Procedure 95002 to determine if the root cause and contributing causes of risk significant performance issues are understood, the extent of condition has been identified, whether safety culture contributed to the performance issues, and if FENOC's corrective actions are sufficient to address the causes and prevent recurrence.
In light of the impacts of the earthquake and tsunami on the reactors in Fukushima, Japan, the NRC conducted inspections of emergency equipment at U.S. reactors. The NRC also established a Near-Term Task Force to review its processes and regulations in light of the incident, and, on July 12, 2011, the Task Force issued its report of recommendations for regulatory changes. On October 18, 2011, the NRC approved the Staff recommendations, and directed the Staff to implement its near-term recommendations without delay. Ultimately, the adoption of the Staff recommendations on near-term actions is likely to result in additional costs to implement plant modifications and upgrades required by the regulatory process over the next several years, which costs are likely to be material.

On February 16, 2012, the NRC issued a request for information to the licensed operators of 11 2009,nuclear power plants, including Beaver Valley Power Station Units 1 and 2, with respect to the NRC’s reviewmodeling of FirstEnergy’s methodologyfuel performance as it relates to "thermal conductivity degradation," which is the potential in older fuel for reduced capacity to transfer heat that could potentially change its performance during various accident scenarios, including loss of coolant accidents. The request for information indicated that this phenomenon has not been accounted for adequately in performance models for the funding of decommissioning of this facility concludedfuel developed by the fuel manufacturer. The NRC is requesting that there was reasonable assurance of adequate decommissioning funding atFENOC provide an analysis to demonstrate that the time permanent termination of operationsNRC regulations are being met. Absent that demonstration, the request indicates that the NRC may consider imposing restrictions on reactor operating limits until the issue is expected. FirstEnergy continues to evaluate the status of its funding obligations for the decommissioning of these nuclear facilities.satisfactorily resolved.

Nuclear Insurance

The Price-Anderson Act limits the public liability which can be assessed with respect to a nuclear power plant to $12.6$12.6 billion (assuming 104 units licensed to operate) for a single nuclear incident, which amount is covered by: (i) private insurance amounting to $375 million;$375 million; and (ii) $12.2$12.2 billion provided by an industry retrospective rating plan required by the NRC pursuant thereto. Under such retrospective rating plan, in the event of a nuclear incident at any unit in the United States resulting in losses in excess of private insurance, up to $118$118 million (but not more than $18$18 million per unit per year in the event of more than one incident) must be contributed for each nuclear unit licensed to operate in the country by the licensees thereof to cover liabilities arising out of the incident. Based on their present nuclear ownership and leasehold interests, FirstEnergy’s maximum potential assessment under these provisions would be $470$470 million (OE-$40 million, NGC-$408 million, and TE-$22 million)million) per incident but not more than $70$70 million (OE-$6 million, NGC-$61 million, and TE-$3 million)million) in any one year for each incident.

In addition to the public liability insurance provided pursuant to the Price-Anderson Act, FirstEnergy has also obtained insurance coverage in limited amounts for economic loss and property damage arising out of nuclear incidents. FirstEnergy is a member of NEIL, which provides coverage (NEIL I) for the extra expense of replacement power incurred due to prolonged accidental outages of nuclear units. Under NEIL I, FirstEnergy’s subsidiaries have policies, renewable yearly, corresponding to their respective nuclear interests, which provide an aggregate indemnity of up to approximately $560$2.0 billion (OE-$168 million (OE-, NGC-$481.7 billion, TE-$90 million NGC-$486 million, TE-$26 million)) for replacement power costs incurred during an outage after an initial 20-week26-week waiting period. Members of NEIL I pay annual premiums and are subject to assessments if losses exceed the accumulated funds available to the insurer. FirstEnergy’s present maximum aggregate assessment for incidents at any covered nuclear facility occurring during a policy year would be approximately $3$13 million (NGC- (OE-$3 million)1 million, NGC-$12 million, and TE-less than $1 million).

FirstEnergy is insured as to its respective nuclear interests under property damage insurance provided by NEIL to the operating company for each plant. Under these arrangements, up to $2.8$2.8 billion of coverage for decontamination costs, decommissioning costs, debris removal and repair and/or replacement of property is provided. FirstEnergy pays annual premiums for this coverage and is liable for retrospective assessments of up to approximately $60$66 million (OE-$6 million, NGC-$5157 million, TE-$2 million, Met


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Ed, Penelec, and JCP&L- less&L-less than $1$1 million in total) each) during a policy year.

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FirstEnergy intends to maintain insurance against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of FirstEnergy’s plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by FirstEnergy’s insurance policies, or to the extent such insurance becomes unavailable in the future, FirstEnergy would remain at risk for such costs.

The NRC requires nuclear power plant licensees to obtain minimum property insurance coverage of $1.1$1.1 billion or the amount generally available from private sources, whichever is less. The proceeds of this insurance are required to be used first to ensure that the licensed reactor is in a safe and stable condition and can be maintained in that condition so as to prevent any significant risk to the public health and safety. Within 30 days of stabilization, the licensee is required to prepare and submit to the NRC a cleanup plan for approval. The plan is required to identify all cleanup operations necessary to decontaminate the reactor sufficiently to permit the resumption of operations or to commence decommissioning. Any property insurance proceeds not already expended to place the reactor in a safe and stable condition must be used first to complete those decontamination operations that are ordered by the NRC. FirstEnergy is unable to predict what effect these requirements may have on the availability of insurance proceeds.
Hydro Relicensing
Yards Creek
The Yards Creek Pumped Storage Project is a400MW hydroelectric project located in Warren County, New Jersey. JCP&L owns an undivided50%interest in the project, and operates the project. PSEG Fossil, LLC, a subsidiary of Public Service Enterprise Group, owns the remaining interest in the plant. The project was constructed in the early 1960s, and became operational in 1965. Authorization to operate the project is by a license issued by the FERC. The existing license expires on February 28, 2013.

In February 2011, JCP&L and PSEG filed a joint application with FERC to renew the license for an additional forty years. The companies are pursuing relicensure through FERC's ILP. Under the ILP, FERC will assess the license applications, issue draft and final Environmental Assessments/Environmental Impact Studies (as required by NEPA), and provide opportunities for intervention and protests by affected third parties. FERC may hold hearings during the two-year ILP licensure period. FirstEnergy expects FERC to issue the new license within the remaining portion of the two-year ILP period. To the extent, however, that the license proceedings extend beyond the February 28, 2013 expiration date for the current license, the current license will be extended yearly as necessary to permit FERC to issue the new license.
Seneca

The Seneca Pumped Storage Project is a451MW hydroelectric project located in Warren County, Pennsylvania owned and operated by FGCO. FGCO holds the current FERC license that authorizes ownership and operation of the project. The current FERC license will expire on November 30, 2015. FERC's regulations call for a five-year relicensing process. On November 24, 2010, and acting pursuant to applicable FERC regulations and rules, FGCO initiated the relicensing process by filing its notice of intent to relicense and PAD in the license docket.

On November 30, 2010, the Seneca Nation filed its notice of intent to relicense and PADs necessary for them to submit a competing application. Section 15 of the FPA contemplates that third parties may file a "competing application" to assume ownership and operation of a hydroelectric facility upon (i) relicensure and (ii) payment of net book value of the plant to the original owner/operator. Nonetheless, FGCO believes it is entitled to a statutory “incumbent preference” under Section 15.

The Seneca Nation and certain other intervenors have asked FERC to redefine the “project boundary” of the hydroelectric plant to include the dam and reservoir facilities operated by the U.S. Army Corps of Engineers. On May 16, 2011, FirstEnergy filed a Petition for Declaratory Order with FERC seeking an order to exclude the dam and reservoir facilities from the project. The Seneca Nation, the New York State Department of Environmental Conservation, and the U.S. Department of Interior each submitted responses to FirstEnergy's petition, including motions to dismiss FirstEnergy's petition. The “project boundary” issue is pending before FERC.

On September 12, 2011, FirstEnergy and the Seneca Nation each filed “Revised Study Plan” documents. These documents describe the parties' respective proposals for the scope of the environmental studies that should be performed as part of the relicensing process. On October 11, 2011, FERC Staff issued a letter order that addressed the Revised Study Plans. In the order, FERC Staff approved FirstEnergy's Revised Study Plan, subject to a finding that the Project is located on “aboriginal lands” of the Seneca Nation. Based on this finding, FERC Staff directed FirstEnergy to consult with the Seneca Nation and other parties about the data set, methodology, and modeling of the hydrological impacts of project operations. FirstEnergy is performing the work necessary to develop a study proposal from which to conduct such consultations. The study process will extend through approximately November of 2013.

FirstEnergy cannot predict the outcome of this matter or estimate the possible loss or range of loss.


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Environmental Matters

Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. The effects of compliance on FirstEnergyCompliance with regard to environmental mattersregulations could have a material adverse effect on FirstEnergy'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 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 ActCAA Compliance

FirstEnergy is required to meet federally-approved SO2 and NOx emissions regulations.regulations under the CAA. FirstEnergy complies with SO2and NOx reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, combustion controls and post-combustion controls, generating more electricity from lower or non-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 SO2penalties. 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.

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

In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W. H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case and seven other similar cases are referred to as the NSR cases. OE’s and Penn’s settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation was approved by the Court on July 11, 2005. This settlement agreement, in the form of a consent decree, requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices or repowering and provides for stipulated penalties for failure to install and operate such pollution controls or complete repowering in accordance with that agreement. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree, including repowering Burger Units 4 and 5 for biomass fuel consumption, are currently estimated to be $399 million for 2010-2012.

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In October 2007, PennFuture and three of its members filed a citizen suit under the federal CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations, in the United States District Court for the Western District of Pennsylvania. In July 2008,three additional complaints were filed against FGCO in the U.S. District Court for the Western District of Pennsylvania seeking damages based on air emissions from the coal-fired Bruce Mansfield Plant air emissions. In addition to seeking damages, two Plant.Twoof the threethese complaints also seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”,manner,” one being a complaint filed on behalf oftwenty-oneindividuals and the other being a class action complaint seeking certification as a class action with theeightnamed plaintiffs as the class representatives. On October 16, 2009, a settlement reached with PennFuture and one of the three individual complainants was approved by the Court, which dismissed the claims of PennFuture and of the settling individual. The other two non-settling individuals are now represented by counsel handling the three cases filed in July 2008. FGCO believes thosethe claims are without merit and intends to defend itself against the allegations made in those threethese 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.

In December 2007, the statestates of New Jersey and Connecticut filed a CAA citizen suitsuits in 2007 alleging NSR violations at the coal-fired Portland Generation Station against Reliant (theGenOn Energy, Inc. (formerly RRI Energy, Inc. and the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU 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 underin violation of the CAA'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. Met-Ed filed a Motion to DismissIn September 2009, the claims in New Jersey’s Amended Complaint and Connecticut’s Complaint in February and September of 2009, respectively. The Court granted Met-Ed's motion to dismiss New Jersey’sJersey's and Connecticut’sConnecticut's claims for injunctive relief against Met-Ed, but denied Met-Ed’sMet-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 allowand from Sithe Energy, and Met-Ed is unable to predict the states to prove either thatoutcome of this matter or estimate the applicationpossible loss or range of the discovery rule or the doctrine of equitable tolling bars application of the statute of limitations.loss.
In January 2009, the EPA issued a NOV to ReliantGenOn Energy, Inc. alleging NSR violations at the coal-fired 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 2009, NOV also alleged NSR violations at the Keystone and Shawville Stationscoal-fired plants 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.matter or estimate the possible loss or range of loss.
In each of May and September 2010, New Jersey submitted interstate pollution transport petitions seeking to reduce Portland Generating Station air emissions under section 126 of the CAA. Based on the September 2010 petition, the EPA has finalized emissions limits and compliance schedules to reduce SO2air emissions by approximately 81% at the Portland Station by January 6, 2015. New Jersey's May 2010 petition is still under consideration by the EPA.
In June 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. alleging that "modifications"“modifications” at the coal-fired Homer City Power StationPlant occurred sincefrom 1988 to the present without preconstruction NSR or permitting underin violation of the CAA's PSD program. In May 2010, the EPA issued a second NOV to Mission, Energy isPenelec, NYSEG and others that have had an ownership interest in Homer City containing in all material respects allegations identical to those included in the June 2008 NOV. In January 2011, the DOJ filed a complaint against Penelec in the U.S. District Court for the Western District of Pennsylvania seeking indemnification frominjunctive relief against Penelec based on alleged “modifications” at Homer City between 1991 to 1994 without preconstruction NSR permitting in violation of the CAA's PSD and Title V permitting programs. The complaint was also filed against the former co-owner, (along withNYSEG, and various current owners of Homer City, including EME Homer City Generation L.P. and affiliated companies, including Edison International. In addition, the Commonwealth of Pennsylvania and the States of New Jersey and New York State Electricintervened and Gas Company)have filed separate complaints regarding Homer City seeking injunctive relief and operatorcivil penalties. In January 2011, another complaint was filed against Penelec and the other entities described above in the U.S. District Court for the Western District of Pennsylvania seeking damages based on Homer City's air emissions as well as certification as a class action and to enjoin Homer City from operating except in a “safe, responsible, prudent and proper manner.” In October 2011, the Court dismissed all of the Homer City Power Station priorclaims with prejudice of the U.S. and the Commonwealth of Pennsylvania and the States of New Jersey and New York and all of the claims of the private parties, without prejudice to its salere-file state law claims in 1999. The scopestate court, against all of Penelec’s indemnity obligationthe defendants, including Penelec.In December 2011, the U.S., the Commonwealth of Pennsylvania and the States of New Jersey and New York all filed notices appealing to the Third Circuit Court of Appeals. Penelec believes the claims are without merit and from Mission Energy is disputed. Penelecintends to defend itself against the allegations made in these complaints, but, at this time, is unable to predict the outcome of this matter.

matter or estimate the loss or possible range of loss. Mission is seeking indemnification from NYSEG and Penelec, the co-owners of Homer City prior to its sale in 1999. On February 13, 2012, the Sierra Club notified the current owner and operator of Homer City, Homer City OL1-OL8 LLC and EME Homer City Generation L.P., that it intends to file a CAA citizen suit regarding its Title V permit and SO2emissions from the Homer City Plant.
In August 2009, the EPA issued a Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, including the PSD, NNSR and Title V regulations, at the Eastlake, Lakeshore, Bay Shore and Ashtabula generatingcoal-fired plants. The EPA’sEPA'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. In September 2009, FGCO also received an informationa request pursuant to Section 114(a) of the CAA requestingfor certain operating and maintenance information and planning


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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 plantPlant may constitute a major modification under the NSR provisionprovisions of the CAA. On December 23,Later in 2009, FGCO also received another information request regarding emission projections for the Eastlake generating plantPlant. In June 2011, EPA issued another Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, specifically opacity limitations and requirements to continuously operate opacity monitoring systems at the Eastlake, Lakeshore, Bay Shore and Ashtabula coal-fired plants. Also, in June 2011, FirstEnergy received an information request pursuant to Sectionsection 114(a) of the CAA.CAA for certain operating, maintenance and planning information, among other information regarding these plants. FGCO intends to comply with the CAA, including EPA’sthe EPA's information requests but, at this time, is unable to predict the outcome of this matter. A June 2006 findingmatter or estimate the possible loss or range 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.

loss.
In August 2008, FirstEnergy2000, AE received aan information request from the EPA for information pursuant to Sectionsection 114(a) of the CAA for certain operatingfrom the EPA requesting that it provide information and documentation relevant to the operation and maintenance information regarding its formerly-owned Avon Lakeof the followingtencoal-fired plants, which collectively include22electric generation units: Albright, Armstrong, Fort Martin, Harrison, Hatfield's Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Niles generating plants, as well as a copy of a nearly identical request directed to the current owner, Reliant Energy, to allow the EPAWillow Island to determine whether these generating sources are complyingcompliance with the NSR provisions under the CAA, which can require the installation of the CAA. FirstEnergy intendsadditional air emission control equipment when a major modification of an existing facility results in an increase in emissions. AE has provided responsive information to fully comply with the EPA’s informationthis and a subsequent request but at this time, is unable to predict the outcome of this matter.matter or estimate the possible loss or range of loss.

In May 2004, AE, AE Supply, MP and WP received a Notice of Intent to Sue Pursuant to CAA §7604 from the Attorneys General of New York, New Jersey and Connecticut and from the PA DEP, alleging that Allegheny performed major modifications in violation of the PSD provisions of the CAA at the following West Virginia coal-fired generation units: Albright Unit 3; Fort Martin Units 1 and 2; Harrison Units 1, 2 and 3; Pleasants Units 1 and 2 and Willow Island Unit 2. The Notice also alleged PSD violations at the Armstrong, Hatfield's Ferry and Mitchell coal-fired plants in Pennsylvania and identifies PA DEP as the lead agency regarding those facilities. In September 2004, AE, AE Supply, MP and WP received a separate Notice of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.
In June 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed suit against AE, AE Supply, MP, PE and WP in the United States District Court for the Western District of Pennsylvania alleging, among other things, that Allegheny performed major modifications in violation of the CAA and the Pennsylvania Air Pollution Control Act at the coal-fired Hatfield's Ferry, Armstrong and Mitchell Plants in Pennsylvania. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. A non-jury trial on liability only was held in September 2010. Plaintiffs filed their proposed findings of fact and conclusions of law in December 2010, Allegheny made its related filings in February 2011 and plaintiffs filed their responses in April 2011. The parties are awaiting a decision from the District Court, but there is no deadline for that decision and we are unable to predict the outcome or estimate the possible loss or range of loss.
18In September 2007, Allegheny received a NOV from the EPA alleging NSR and PSD violations under the CAA, as well as Pennsylvania and West Virginia state laws at the coal-fired Hatfield's Ferry and Armstrong plants in Pennsylvania and the coal-fired Fort Martin and Willow Island plants in West Virginia.
FirstEnergy intends to vigorously defend against the CAA matters described above but cannot predict their outcomes or estimate the possible loss or range of loss.
State Air Quality Compliance
In early 2006, Maryland passed the Healthy Air Act, which imposes state-wide emission caps on SO2and NOx, requires mercury emission reductions and mandates that Maryland join the RGGI and participate in that coalition's regional efforts to reduce CO2emissions. On April 20, 2007, Maryland became the tenth state to join the RGGI. The Healthy Air Act provides a conditional exemption for the R. Paul Smith coal-fired plant for NOx, SO2and mercury, based on a 2006 PJM declaration that the plant is vital to reliability in the Baltimore/Washington DC metropolitan area. Pursuant to the legislation, the MDE passed alternate NOx and SO2limits for R. Paul Smith, which became effective in April 2009. However, R. Paul Smith is still required to meet the Healthy Air Act mercury reductions of80%which began in 2010. The statutory exemption does not extend to R. Paul Smith's CO2emissions. Maryland issued final regulations to implement RGGI requirements in February 2008.FourteenRGGI auctions have been held through the end of calendar year 2011. RGGI allowances are also readily available in the allowance markets, affording another mechanism by which to secure necessary allowances. On March 14, 2011, MDE requested PJM perform an analysis to determine if termination of operation at R. Paul Smith would adversely impact the reliability of electrical service in the PJM region under current system conditions. On June 30, 2011, PJM notified MDE that termination of operation at R. Paul Smith would adversely impact the reliability of electrical service in the PJM region absent transmission system upgrades. On January 26, 2012, FirstEnergy announced that R. Paul Smith is among nine coal-fired plants it intends to retire by September 1, 2012, subject to review of reliability impacts by PJM. FirstEnergy is unable to predict the outcome of this matter or estimate the possible loss or range of loss.
In January 2010, the WVDEP issued a NOV for opacity emissions at the Pleasants coal-fired plant. In August 2011, FirstEnergy and WVDEP resolved the NOV through a Consent Order requiring installation of a reagent injection system to reduce opacity by September 2012.
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 NOXNOx and SO2 emissions intwophases (Phase I in 2009 for NOX, (2009/2010 for SO2and Phase II in 2015 for both NOX and SO2)2015), ultimately capping SO2


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emissions in affected states to2.5 milliontons annually and NOXNOx emissions to1.3 milliontons annually. CAIR was challenged inIn 2008, the U.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.” In September 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. In December 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, 2008Court's opinion. On July 10, 2009, the U.S.The 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“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's future cost of compliance with these regulations may be substantial and will depend, in part, on the action taken by the EPA in response to the Court’s ruling.

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,July 2011, the EPA finalized the CAMR, which provides a cap-and-trade programCSAPR, to reduce mercury replace CAIR,requiring reductions of NOx and SO2emissions from coal-firedintwo phases (2012 and 2014), ultimately capping SO2emissions in affected states to2.4 milliontons annually and NOx emissions to1.2 milliontons annually. CSAPR allows trading of NOx and SO2emission allowances between power plants located in two phases; initially, capping national mercury the same state and interstate trading of NOx and SO2emission allowances with some restrictions. On February 21, 2012, the EPA revised certain CASPR state budgets (for Florida, Louisiana, Michigan, Mississippi, Nebraska, New Jersey, New York, Texas, and Wisconsin and new unit set-asides in Arkansas and Texas), certain generating unit allocations (for some units in Alabama, Indiana, Kansas, Kentucky, Ohio and Tennessee) for NOx and SO2emissions at 38 tonsand delayed from 2012 to 2014 certain allowance penalties that could apply with respect to interstate trading of NOx and SO2emission allowances.On December 30, 2011, CSAPR was stayed by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the U.S. Court of Appeals for the District of Columbia. Columbia Circuit pending a decision on legal challenges raised in appeals filed by various stakeholders and scheduled to be argued before the Court on April 13, 2012. The Court ordered EPA to continue administration of CAIR until the Court resolves the CSAPR appeals. Depending on the outcome of these proceedings and how any final rules are ultimately implemented, FGCO's and AE Supply's future cost of compliance may be substantial and changes to FirstEnergy's operations may result.

During 2011, FirstEnergy recorded pre-tax impairment charges of approximately$6 million($1 millionfor FES and$5 millionfor AE Supply) for NOx emission allowances that were expected to be obsolete after 2011 and approximately$21 million($18 millionfor FES and$3 millionfor AE Supply) for excess SO2emission allowances in inventory that it expects will not be consumed in the future.
Hazardous Air Pollutant Emissions
On December 21, 2011, the EPA finalized the MATS to establish emission standards for mercury, hydrochloric acid and various metals for electric generating units. The MATS establishes emission limits for mercury, PM, and HCL for all existing and new coal-fired electric generating units effective in April 2015 and allows averaging of emissions from multiple units located at a single plant. Under the CAA, state permitting authorities can grant an additional compliance year through April 2016, as needed, including instances when necessary to maintain reliability where electric generating units are being closed. In addition, an EPA enforcement policy document contemplates up to an additional year to achieve compliance, through April 2017, under certain circumstances for reliability critical units. On January 26, 2012 and February 8, 2008,2012, FGCO, MP and AE Supply announced the Court vacated the CAMR, ruling that the EPA failedretirement by September 1, 2012 (subject to take the necessary steps to “de-list”a reliability review by PJM) of nine coal-fired power plants from its hazardous air pollutant program(Albright, Armstrong, Ashtabula, Bay Shore except for generating unit 1, Eastlake, Lake Shore, R. Paul Smith, Rivesville and therefore, could not promulgateWillow Island) with a cap-and-trade program. The EPA petitioned for rehearingtotal capacity of3,349megawatts (generating, on average, approximately ten percent of the electricity produced by the entire Court, which deniedcompanies over the petition in May 2008. In October 2008, the EPA (and an industry group) petitioned the U.S. Supreme Court for review of the Court’s ruling vacating CAMR. On February 6, 2009, the EPA movedpast three years) due to dismiss its petition for certiorari. On February 23, 2009, the Supreme Court dismissed the EPA’s petition and denied the industry group’s petition. On October 21, 2009, the EPA opened a 30-day comment period on a proposed consent decree that would obligate the EPA to propose MACT regulations for mercuryMATS and other hazardous air pollutants by March 16, 2011, andenvironmental regulations. In addition, MP will make a filing with the WVPSC to finalizeprovide them with information regarding the regulations by November 16, 2011. FGCO’sretirement of its plants. Depending on how the MATS are ultimately implemented, FirstEnergy's future cost of compliance with MACT regulationsMATS may be substantial and will depend on the action taken by the EPA and on how any future regulations are ultimately implemented.other changes to FirstEnergy's operations may result.

Pennsylvania has submitted a new mercury rule for EPA approvalOn February 24, 2012, PJM notified FirstEnergy of its preliminary analysis of the reliability impacts that does not provide a cap-and-trade approach asmay result from closure of the older competitive coal-fired generating units. PJM's preliminary analysis indicated that there would be significant reliability concerns that will need to be addressed. FirstEnergy intends to continue to actively engage in discussions with PJM regarding this notification, including the CAMR, but rather follows a command-and-control approach imposing emission limits on individual sources. On December 23, 2009, the Supreme Courtpossible continued operation of Pennsylvania affirmed the Commonwealth Court of Pennsylvania ruling that Pennsylvania’s mercury rule is “unlawful, invalid and unenforceable” and enjoined the Commonwealth from continued implementation or enforcement of that rule.

certain plants.
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.

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There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the 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, in June 2009. Certain states, primarily the northeastern states participating in the RGGI and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.
In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that required FirstEnergy to measure and report GHG emissions commencing in 2010. In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA's finding concludes that concentrations of several key GHGs increase the threat of climate change and may be regulated as “air pollutants” under the CAA. In April 2010, the EPA finalized new 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 would not be triggered for electric generating plants and other stationary sources until January 2, 2011, at the earliest. In May 2010, the EPA finalized new thresholds for GHG emissions that define when permits under the CAA's NSR program would be required. The EPA established an emissions applicability threshold of75,000tons per year of CO2equivalents effective January 2, 2011, for existing facilities under the CAA's PSD program.
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 man-made GHG, including CO2, emitted by developed countries


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by 2012. A December 2009 U.N. Climate Change Conference in Copenhagen did not reach a consensus on a successor treaty to the Kyoto Protocol, but did take note of the Copenhagen Accord, a non-binding political agreement whichthat recognized the scientific view that the increase in global temperature should be belowtwodegrees Celsius, includedCelsius; includes a commitment by developed countries to provide funds, approaching $30$30 billionover the next three years with a goal of increasing to $100$100 billionby 2020,2020; and establishedestablishes the “Copenhagen Green“Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. OnceTo the extent that 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 targets from 2020, while developing countries, including Brazil, China and India, would agree to take mitigation actions, subject to their domestic measurement, reporting and verification. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHGA December 2011 U.N. Climate Change Conference 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 considerDurban, Africa, established a number of measures to regulate GHG emissions. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states, led by California, have coordinated effortsnegotiating process to develop regional strategiesa new post-2020 climate change protocol, called the “Durban Platform for Enhanced Action”. This negotiating process contemplates developed countries, as well as developing countries such as China, India, Brazil, and South Africa, to control emissions ofundertake legally binding commitments post-2020. In addition, certain GHGs.

On April 2, 2007,countries agreed to extend the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. In December 2009, the EPA released its final “Endangerment and Cause or Contribute FindingsKyoto Protocol for Greenhouse Gases under the Clean Air Act.” The EPA’s finding concludes that the atmospheric concentrations of several key GHG 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 GHG and hence to the threat of climate change. Although the EPA’s finding does not establish emission requirements for motor vehicles, such requirements are expected to occur through further rulemakings. Additionally, while the EPA’s endangerment findings do not specifically address stationary sources, including electric generating plants  EPA’s expected establishment of emission requirements for motor vehicles would be expected to support the establishment of future emission requirements by the EPA for stationary sources. In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that will require FirstEnergy to measure GHG emissionssecond commitment period, commencing in 20102013 and submit reports commencingexpiring in 2011. Also in September 2009, EPA proposed new thresholds for GHG emissions that define when CAA permits under the NSR and Title V operating permits programs would be required. EPA is proposing a major source emissions applicability threshold of 25,000 tons per year (tpy) of carbon dioxide equivalents (CO2e) for existing facilities under the Title V operating permits program and the Prevention of Significant Determination (PSD) portion of NSR. EPA is also proposing a significance level between 10,000 and 25,000 tpy CO2e to determine if existing major sources making modifications that result in an increase of emissions above the significance level would be required to obtain a PSD permit.2018 or 2020.

On September 21,In 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. 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. While FirstEnergy is notThe U.S. Supreme Court granted a partywrit of certiorari to either litigation, shouldreview the courtsdecision of appeals decisions be affirmed or not subjectedthe Second Circuit. On June 20, 2011, the U.S. Supreme Court reversed the Second Circuit but failed to further review, FirstEnergy and/or one or moreanswer the question of its subsidiaries could be named inthe extent to which actions making similar allegations.

for damages based on GHG emissions may remain viable. The Court remanded to the Second Circuit the issue of whether the CAA preempted state common law nuisance actions.
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 of its 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 ActCWA and its amendments, apply to FirstEnergy's plants. In addition, Ohio, New Jersey and Pennsylvaniathe states in which FirstEnergy operates have water quality standards applicable to FirstEnergy's operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such authority.

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On September 7,In 2004, the EPA established new performance standards under Section 316(b) of the Clean Water ActCWA for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). On January 26,In 2007, the United States Court of Appeals for the Second Circuit remandedinvalidated portions of the rulemaking dealing with impingement mortalitySection 316(b) performance standards and entrainment back to the EPA for further rulemaking and eliminatedhas taken 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. OnIn 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 ActCWA authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. On March 28, 2011, the EPA is developingreleased a new proposed regulation under Section 316(b) of the Clean Water Act consistent withCWA generally requiring fish impingement to be reduced to a12%annual average and studies to be conducted at the opinionsmajority of our existing generating facilities to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic life. On July 19, 2011, the Supreme Court andEPA extended the Court of Appeals which have created significant uncertainty aboutpublic comment period for the specific nature, scope and timing of thenew proposed Section 316(b) regulation by30days but stated its schedule for issuing a final performance standard.rule remains July 27, 2012. 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. Depending on the results of such studies and the EPA’sEPA'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 April 2011, the U.S. Attorney's Office in Cleveland, Ohio has advised FGCO that it is no longer considering prosecution under the Clean Water ActCWA 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. On August 5, 2011, EPA issued an information request pursuant to Sections 308 and 311 of the CWA for certain information pertaining to the oil spills and spill prevention measures at FirstEnergy facilities. FirstEnergy responded on October 10, 2011. On February 1, 2012, FirstEnergy executed a tolling agreement with the EPA extending the statute of limitations to July 31, 2012. FGCO does not anticipate any losses resulting from this matter to be material.
In May 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club filed a CWA citizen suit alleging violations of arsenic limits in the NPDES water discharge permit for the fly ash impoundments at the Albright Station seeking unspecified civil penalties and injunctive relief. The MP filed an answer on July 11, 2011, and a motion to stay the proceedings on July 13, 2011. On January 3, 2012, the Court denied MP's motion to dismiss or stay the CWA citizen suit but without prejudice to re-filing in the future. MP is unablecurrently seeking relief from the arsenic limits through WVDEP agency review.



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In June 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club served a60-Day Notice of Intent required prior to filing a citizen suit under the CWA for alleged failure to obtain a permit to construct the fly ash impoundments at the Albright Plant.
FirstEnergy intends to vigorously defend against the CWA matters described above but, except as indicated above, cannot predict their outcomes or estimate the possible loss or range of loss.
Monongahela River Water Quality
In late 2008, the PA DEP imposed water quality criteria for certain effluents, including TDS and sulfate concentrations in the Monongahela River, on new and modified sources, including the scrubber project at the coal-fired Hatfield's Ferry Plant. These criteria are reflected in the current PA DEP water discharge permit for that project. AE Supply appealed the PA DEP's permitting decision, which would require it to incur estimated costs in excess of$150 millionin order to install technology to meet TDS and sulfate limits in the permit or negatively affect its ability to operate the scrubbers as designed. The permit has been independently appealed by Environmental Integrity Project and Citizens Coal Council, which seeks to impose more stringent technology-based effluent limitations. Those same parties have intervened in the appeal filed by AE Supply, and both appeals have been consolidated for discovery purposes. An order has been entered that stays the permit limits that AE Supply has challenged while the appeal is pending. A hearing on the parties' appeals was scheduled to begin in September 2011, however the Court stayed all prehearing deadlines on July 15, 2011 to allow the parties additional time to work out a settlement, and has rescheduled a hearing, if necessary, for July 2012. If these settlement discussions are successful, AE Supply anticipates that its obligations will not be material. AE Supply intends to vigorously pursue these issues, but cannot predict the outcome of these appeals or estimate the possible loss or range of loss.
In a parallel rulemaking, the PA DEP recommended, and in August 2010, the Pennsylvania Environmental Quality Board issued, a final rule imposing end-of-pipe TDS effluent limitations. FirstEnergy could incur significant costs for additional control equipment to meet the requirements of this matter.rule, although its provisions do not apply to electric generating units until the end of 2018, and then only if the EPA has not promulgated TDS effluent limitation guidelines applicable to such units.
In December 2010, PA DEP submitted its CWA 303(d) list to the EPA with a recommended sulfate impairment designation for an approximately68mile stretch of the Monongahela River north of the West Virginia border. In May 2011, the EPA agreed with PA DEP's recommended sulfate impairment designation. PA DEP's goal is to submit a final water quality standards regulation, incorporating the sulfate impairment designation for EPA approval by May, 2013. PA DEP will then need to develop a TMDL limit for the river, a process that will take approximatelyfiveyears. Based on the stringency of the TMDL, FirstEnergy may incur significant costs to reduce sulfate discharges into the Monongahela River from the coal-fired Hatfield's Ferry and Mitchell Plants in Pennsylvania and the coal-fired Fort Martin Plant in West Virginia.
In October 2009, the WVDEP issued the water discharge permit for the Fort Martin Plant. Similar to the Hatfield's Ferry water discharge permit, the Fort Martin permit imposes effluent limitations for TDS and sulfate concentrations. The permit also imposes temperature limitations and other effluent limits for heavy metals that are not contained in the Hatfield's Ferry water discharge permit. Concurrent with the issuance of the Fort Martin permit, WVDEP also issued an administrative order that sets deadlines for MP to meet certain of the effluent limits that are effective immediately under the terms of the permit. MP appealed the Fort Martin permit and the administrative order. The appeal included a request to stay certain of the conditions of the permit and order while the appeal is pending, which was granted pending a final decision on appeal and subject to WVDEP moving to dissolve the stay. The appeals have been consolidated. MP moved to dismiss certain of the permit conditions for the failure of the WVDEP to submit those conditions for public review and comment during the permitting process. An agreed-upon order that suspends further action on this appeal, pending WVDEP's release for public review and comment on those conditions, was entered on August 11, 2010. The stay remains in effect during that process. The current terms of the Fort Martin permit would require MP to incur significant costs or negatively affect operations at Fort Martin. Preliminary information indicates an initial capital investment in excess of the capital investment that may be needed at Hatfield's Ferry in order to install technology to meet the TDS and sulfate limits in the Fort Martin permit, which technology may also meet certain of the other effluent limits in the permit. Additional technology may be needed to meet certain other limits in the permit. MP intends to vigorously pursue these issues but cannot predict the outcome of these appeals or estimate the possible loss or range of loss.
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's evaluation of the need for future regulation. In February 2009, the EPA requested comments from the states on options for regulating coal combustion wastes,residuals, including regulationwhether they should be regulated as hazardous or non-hazardous waste or regulation as a hazardous waste. In March and June 2009, the EPA requested information from FGCO’s Bruce Mansfield Plant regarding the management of coal combustion wastes.
In December 2009, EPA provided to FGCO the findings of its review of the Bruce Mansfield Plant’s coal combustion waste management practices.  EPA observed that the waste management structures and the Plant “appeared to be well maintained and in good working order” and recommended only that FGCO “seal and maintain all asphalt surfaces.” On December 30, 2009, in an advancedadvance notice of public rulemaking, the EPA saidasserted that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. Additional regulationsIn May 2010, the EPA proposedtwooptions for additional regulation of fossil-fuelcoal combustion residuals, including the option of regulation as a special waste productsunder the EPA's hazardous waste management program which could have a significant impact on ourthe management, beneficial use and disposal of coal ash. FGCO'scombustion residuals. FirstEnergy's future cost of compliance with any coal combustion wasteresiduals regulations whichthat may be promulgated could


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be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the EPA or the states. Compliance with those regulations could have an adverse impact on FirstEnergy's results of operations and financial condition.
LBR CCB impoundment is expected to run out of disposal capacity for disposal of CCBs from the BMP between 2016 and 2018. BMP is pursuing several CCB disposal options.
The UtilitiesCertain of our 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 ofDecember 31, 2009,2011, based on estimates of the total costs of cleanup, the Utilities'Utility Registrants' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay.Total liabilities of approximately $101$106 million (JCP(JCP&L - - $74$70 million, TE - $1$1 million, CEI - $1$1 million, FGCO - $1$1 millionand FirstEnergyFE - $24$33 million) have been accrued throughDecember 31, 2009.2011. Included in the total are accrued liabilities of approximately $67$63 millionfor 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. On July 11, 2011, FirstEnergy was found to be a potentially responsible party under CERCLA, indirectly liable for a portion of past and future clean-up costs at certain legacy MGP sites, estimated to total approximately$59 million. FirstEnergy recognized an additional expense of$29 millionduring the second quarter of 2011;$30 millionhad previously been reserved prior to 2011.FirstEnergy determined that it is reasonably possible that it or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the possible losses or range of losses cannot be determined or reasonably estimated at this time.

Fuel Supply

FESFirstEnergy currently has long-term coal contracts with various terms to acquire approximately 22.734.5 million tons of coal for the year 2010,2012 which is approximately 109%90% of its 20102012 coal requirements of 20.838.5 million tons. This coal requirement excludes the impact of our recently announced decision to close nine older coal-fired plants by September 1, 2012, subject to review for reliability impacts by PJM. This contract coal is produced primarily from mines located in Ohio, Pennsylvania, Kentucky, West Virginia, Montana and Wyoming. The contracts expire at various times through December 31, 2030. See “Environmental Matters” for factors pertaining to meeting environmental regulations affecting coal-fired generating units.

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In July 2008, FEV entered into a joint venture with the Boich Companies, a Columbus, Ohio-based coal company, to acquire a majority stake in the Bull Mountain Mine Operations, now called Signal Peak, near Roundup, Montana. This joint venture is part of FirstEnergy’s strategy to secure high-quality fuel supplies at attractive prices to maximize the capacity of its fossil generating plants. In a related transaction, FGCO entered into a 15-year agreement to purchase up to 10 million tons of bituminous western coal annually from the mine. FirstEnergy also entered into agreements with the rail carriers associated with transporting coal from the mine to its generating stations, and began taking delivery of the coal in late 2009. The joint venture has the right to resell Signal Peak coal tonnage not used at FirstEnergy facilities and has call rights on such coal above certain levels.

FirstEnergy has contracts for all uranium requirements through 20112012 and a portion of uranium material requirements through 2016.2024. Conversion services contracts fully cover requirements through 20112012 and partially fill requirements through 2016.2024. Enrichment services are contracted for essentially all of the enrichment requirements for nuclear fuel through 2017.2020. A portion of enrichment requirements is also contracted for through 2024. Fabrication services for fuel assemblies are contracted for both Beaver Valley units and Davis Besse through 2013 and Davis-Besse through 2025 and through the current operating license period for Perry (through approximately 2026). The Davis-Besse fabrication contract also has an extension provision for services for additional consecutive reload batches through the current operating license period (approximately 2017).Perry. In addition to the existing commitments, FirstEnergy intends to make additional arrangements for the supply of uranium and for the subsequent conversion, enrichment, fabrication, and waste disposal services.

On-site spent fuel storage facilities are expected to be adequate for PerryBeaver Valley Unit 1 through 2010; facilities at2014. Davis-Besse has adequate storage through 2017. FENOC is taking actions to extend the spent fuel storage capacity for Beaver Valley Units 1 and 2 and Perry. Plant modifications to increase the storage capacity of the existing spent fuel storage pool at Beaver Valley Unit 2 were approved by the NRC on April 29, 2011 and the plant modifications are expected to be adequatecomplete in 2012. Once this expansion is complete, Beaver Valley Unit 2 will have spent fuel pool storage capacity through 20152022. Dry fuel storage is also being pursued at Beaver Valley with completion projected by the end of 2014. Perry dry fuel storage facilities have been completed with the initial dry fuel storage loading campaign targeted for 2012. Both Beaver Valley Unit 2 and 2010, respectively. Davis-Besse has adequatePerry maintain sufficient fuel storage capability to continue operations through 2017.the targeted completion dates of their respective storage expansion projects. After current on-site storage capacity at the plants is exhausted, additional storage capacity will have to be obtained either through plant modifications, interim off-site disposal, or permanent waste disposal facilities. FENOC is currently taking actions to extend the spent fuel storage capacity for Perry and Beaver Valley. Plant modifications to increase the storage capacity of the existing spent fuel storage pool at Beaver Valley Unit 2 were submitted to the NRC for approval during the second quarter of 2009. The NRC has requested additional information to complete the license review process and this information will be provided in early 2010. Dry fuel storage is also being pursued at Perry and Beaver Valley, with Perry implementation scheduled to complete by the end of 2010 and Beaver Valley to be complete by the end of 2014.

The Federal Nuclear Waste Policy Act of 1982 provided for the construction of facilities for the permanent disposal of high-level nuclear wastes, including spent fuel from nuclear power plants operated by electric utilities. NGC has contracts with the DOE for the disposal of spent fuel for Beaver Valley, Davis-Besse and Perry. Yucca Mountain was approved in 2002 as a repository for underground disposal of spent nuclear fuel from nuclear power plants and high level waste from U.S. defense programs. The DOE submitted the license application for Yucca Mountain to the NRC on June 3, 2008. However,On March 3, 2010, the DOE filed a motion to withdraw its Yucca Mountain license application with prejudice. The ASLB denied the DOE's withdrawal motion on June 29, 2010. On September 9, 2011, the NRC issued an Order (CLI-11-07) stating that it was evenly divided on whether to overturn or uphold the ASLB's decision, and directing the ASLB to complete all necessary and appropriate case management activities by the close of the fiscal year. The current Administration has stated the Yucca Mountain repository will not be completed and a Federal review of potential alternative strategies will beis being performed. The President's 2011 budget proposal eliminated funding for Yucca Mountain, and the 2011 DOE appropriation did not include any funds for Yucca Mountain. Likewise, the President's 2012 budget proposal does not provide for funding of Yucca Mountain.

In parallel, several parties filed actions in the U.S. Circuit Court of Appeals for the D.C. Circuit challenging the Department's authority to withdraw the license application in light of its obligations under the Nuclear Waste Policy Act. The first case filed was In re: Aiken County, filed on February 19, 2010. Robert L. Ferguson, et al. filed a petition on February 25, 2010; State of South Carolina filed


23


on March 26, 2010; and State of Washington filed on April 13, 2010. These cases have since been consolidated. On May 3, 2010, the D.C. Circuit granted a motion by the National Association of Regulatory Utility Commissioners to intervene. Oral arguments were heard by the D.C. Circuit on March 22, 2011. The D.C. Circuit dismissed the petitions for lack of jurisdiction on July 1, 2011, finding a lack of finality and ripeness until the Commission acts on DOE's motion to withdraw or rules on the license application. In response to the NRC's order from September 2011, the states and other interested parties re-commenced their challenge at the D. C. Circuit, in Aiken County et al., No. 11-1271. Briefing in that appeal was recently completed, and oral argument has been set for May 2, 2012. In light of this uncertainty, FirstEnergy intends to make additional arrangements for storage capacity as a contingency for the continuing delays withof the DOE acceptance of spent fuel for disposal.

Fuel oil and natural gas are used primarily to fuel peaking units and/or to ignite the burners prior to burning coal when a coal-fired plant is restarted. Fuel oil requirements have historically been low and are forecasted to remain so; requirementsso. Requirements are expected to average approximately 54 million gallons per year over the next five years. Due to the volatility of fuel oil prices, FirstEnergy has adopted a strategy of either purchasing fixed-priced oil for inventory or using financial instruments to hedge against price risk. Natural gas is currently consumed primarily by peaking units and no natural gas demand is forecasted at less than 7 million mcf in 2010. First Energy purchased a partially completed combined cycle combustion turbine plant in Fremont Ohio. Construction is scheduled to be completed in late 2010 and generation is forecasted for 2011. Because of high price volatility and the unpredictability of unit dispatch, natural gas futures are purchased based on forecasted demand to hedge against price movements.2012.

System Demand

The 2009 net2011 maximum hourly demand for each of the Utilities was:

OE—6,070 MW on July 21, 2011;
·OE–5,156 MW on June 25, 2009;
Penn—1,048 MW on July 21, 2011;
CEI—4,648 MW on July 21, 2011;
·Penn–879 MW on June 25, 2009;
TE—2,286 MW on July 21, 2011;
JCP&L—6,588 MW on July 22, 2011;
·CEI–3,843 MW on June 25, 2009;
Met-Ed—3,094 MW on July 22, 2011;
Penelec—3,128 MW on July 22, 2011;
·TE–2,009 MW on June 25, 2009;
MP—1,989 MW on July 21, 2011;
PE—2,969 MW on July 21, 2011; and
WP—4,017 MW on July 21, 2011
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·JCP&L–5,738 MW on August 10, 2009;
·Met-Ed–2,839 MW on August 10, 2009; and
·Penelec–2,679 MW on August 10, 2009.
Supply Plan

Regulated Commodity Sourcing

TheCertain of the Utilities have a default service obligationobligations to provide the required power supply to non-shopping customers who have elected to continue to receive service under regulated retail tariffs. The volume of these sales can vary depending on the level of shopping that occurs. Supply plans vary by state and by service territory. JCP&L’s default service or BGS supply is secured through a statewide competitive procurement process approved by the NJBPU. The Ohio UtilitiesCompanies', Pennsylvania Companies' and Penn’sPE's Maryland default service supplies are provided through a competitive procurement process approved by the PUCO (under the ESP), PPUC (under the DSP) and PPUC,MDPSC (under the SOS), respectively. The default service supply for Met-Ed and Penelec is secured through a FERC-approved agreement with FES, but will move to a competitive procurement process in 2011. If any unaffiliated suppliers failsupplier fails to deliver power to any one of thethose Utilities’ service areas, the Utility serving that area may need to procure the required power in the market in their role as a PLR.

POLR. West Virginia electric generation continues to be regulated by the WVPSC.
Unregulated Commodity Sourcing

The Competitive Energy Services segment, through FES has retail and wholesale competitive load-serving obligations in Ohio, New Jersey, Maryland, Pennsylvania, Michigan and Illinois serving both affiliated and non-affiliated companies. FES provides energy products and services to customers under various PLR, shopping, competitive-bid and non-affiliated contractual obligations. In 2009, FES’ generation was used to serve two main obligations. Affiliated companies utilized approximately 76% of FES’ total generation. Direct retail customers utilized approximately 18% of FES' total generation. Geographically, approximately 67% of FES’ obligation is located in the MISO market area and 33% is located in the PJM market area.
FESAE Supply, provides energy and energy related services, including the generation and sale of electricity and energy planning and procurement through retail and wholesale competitive supply arrangements. FES controls (either through ownership, lease, affiliated power contracts or participation in OVEC) 14,346 MW of installed generating capacity. FES supplies the power requirements of its competitive load-serving obligations through a combination of subsidiary-owned generation, non-affiliated contracts and spot market transactions.

FES and AE Supply have retail and wholesale competitive load-serving obligations in Ohio, Pennsylvania, Illinois, Maryland, Michigan and New Jersey, serving both affiliated and non-affiliated companies. FES and AE Supply provide energy products and services to customers under various POLR, shopping, competitive-bid and non-affiliated contractual obligations. Geographically, most of FES’ and AE Supply's obligations are in the PJM market area where all of its respective generation facilities are located.
Regional Reliability

FirstEnergy’s operating companiesAll of FirstEnergy's facilities are located within MISO and PJM and operate under the reliability oversight of a regional entity known as ReliabilityFirst.RFC. This regional entity operates under the oversight of the NERC in accordance with a Delegation Agreement approved by the FERC. ReliabilityFirstRFC began operations under the NERC on January 1, 2006. On July 20, 2006, the NERC was certified by the FERC as the ERO


24


in the United States pursuant to Section 215 of the FPA and ReliabilityFirst RFC was certified as a regional entity. ReliabilityFirst represents the consolidation of the ECAR, Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability councils into a single regional reliability organization.

Competition

As a result of actions taken by state legislative bodies, major changes in the electric utility business have occurred in portions of the United States, including Ohio, New Jersey, Pennsylvania and PennsylvaniaMaryland, where FirstEnergy’smost of FirstEnergy utility subsidiaries operate. These changes have altered the way traditional integrated utilities conduct their business. FirstEnergy has aligned its business units to accommodate its retail strategy and participate in the competitive electricity marketplace (see Management's Discussion and Analysis)Analysis for more information regarding FirstEnergy's Competitive Energy Services segment). FirstEnergy’s
FirstEnergy's Competitive Energy Services segment participates in deregulated energy markets in Ohio, Pennsylvania, Maryland, Michigan, New Jersey and Illinois, through FES.FES and AE Supply. In these markets, the Competitive Energy Services segment competes: (1) to provide retail generation service directly to end users; (2) to provide wholesale generation service to utilities, municipalities and co-operatives, which, in turn, resell to their end users, and (3) in the wholesale market. The success of the Competitive Energy Services segment is driven by its ability to successfully compete against other retail markets and/or generators and to produce revenues that exceed costs.
Seasonality

In New Jersey, JCP&L has procuredThe sale of electric generation supply to serve its BGS customers since 2002 throughpower is generally a statewide auction process approved by the NJBPU. The auction is designed to procure supply for BGS customers atseasonal business and weather patterns can have a cost reflective of market conditions. On May 1, 2008, the Governor of Ohio signed SB221 into law, which became effective July 31, 2008. The new law provides two options for pricing generation in 2009 and beyond – through a negotiated rate plan or a competitive bidding process (see PUCO Rate Matters above). In Pennsylvania, all electric distribution companies will be required to secure generation for customers in competitive markets by 2011.

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FirstEnergy remains focusedmaterial impact on managing the transition to competitive marketsFirstEnergy’s operating results. Demand for electricity in Pennsylvania. On October 15, 2008,our service territories historically peaks during the Governorsummer and winter months, with market prices also generally peaking at that time. Accordingly, FirstEnergy’s annual results of Pennsylvania signed House Bill 2200 into law, which became effectiveoperations and liquidity position may depend disproportionately on November 14, 2008, as Act 129 of 2008. The new law outlines a competitive procurement processits operating performance during the summer and sets targets for energy efficiencywinter. Mild weather conditions may result in lower power sales and conservation (see PPUC Rate Matters above).consequently lower earnings.

Research and Development

The Utilities, FES, FGCO and FENOC participate in the funding of EPRI, which was formed for the purpose of expanding electric research and development (R&D)R&D under the voluntary sponsorship of the nation’s electric utility industry -— public, private and cooperative. Its goal is to mutually benefit utilities and their customers by promoting the development of new and improved technologies to help the utility industry meet present and future electric energy needs in environmentally and economically acceptable ways. EPRI conducts research on all aspects of electric power production and use, including fuels, generation, delivery, energy management and conservation, environmental effects and energy analysis. The majority of EPRI’s research and development projects are directed toward practical solutions and their applications to problems currently facing the electric utility industry.

FirstEnergy participates in other initiatives with industry R&D consortiums and universities to address technology needs for its various business units. Participation in these consortiums helps the company address research needs in areas such as plant operations and maintenance, major component reliability, environmental controls, advanced energy technologies, and T&D Systemtransmission and distribution system infrastructure to improve performance, and develop new technologies for advanced energy and grid applications.


25


24
Executive Officers
Name Age Positions Held During Past Five Years Dates
A. J. Alexander 60  President and Chief Executive Officer (A)(B) *-present
    Chief Executive Officer (F) *-present
    President and Chief Executive Officer (H) 2011-present
    President (C)(D) *-2008
       
L. M. Cavalier 60  Senior Vice President, Human Resources (B) *-present
    Senior Vice President, Human Resources (H) 2011-present
       
M. T. Clark 61  President and Chief Financial Officer (G)(L) 2012-present
    Executive Vice President and Chief Financial Officer (A)(B)(C)(D)(E)(F) 2009-present
    Executive Vice President and Chief Financial Officer (H)(I)(J)(K) 2011-present
    Executive Vice President and Chief Financial Officer (G) 2011
    Executive Vice President, Strategic Planning & Operations (A)(B) 2008-2009
    Senior Vice President, Strategic Planning & Operations (B) *-2008
       
M. J. Dowling 47 Senior Vice President, External Affairs (B)(H) 2011-present
    Vice President, External Affairs (B) 2010-2011
    Vice President, Communications (B) 2008-2010
    Vice President, Governmental Affairs (B) 2007-2008
    Vice President (B) *-2007
       
C. E. Jones 56  Senior Vice President & President, FirstEnergy Utilities (B) 2010-present
    Senior Vice President & President, FirstEnergy Utilities (H) 2011-present
    President (J)(K) 2011-present
    President (C)(D) 2010-present
    Senior Vice President & President, FirstEnergy Utilities (A) 2010-2011
    Senior Vice President, Energy Delivery & Customer Service (B) 2009-2010
    President (E) 2007-2009
    Senior Vice President (B)(C)(D) *-2007
       
J. H. Lash 61  President FE, Generation (B)(H) 2011-present
    Chief Nuclear Officer (F) 2011-present
    President (I) 2011-present
    President and Chief Nuclear Officer (F) 2010-2011
    Senior Vice President and Chief Operating Officer (F) 2007-2010
    Vice President, Beaver Valley (F) *-2007
       
G. R. Leidich 61  Executive Vice President, Integration (A)(B)(H)(M) 2011
    President (G)(M) 2011
    Executive Vice President & President, FirstEnergy Generation (A)(B)(M) 2008-2011
    Senior Vice President, Operations (B) 2007-2008
    President and Chief Nuclear Officer (F) *-2007
       
J. F. Pearson 57  Vice President and Treasurer (A)(B)(C)(D)(E)(F) *-present
    Vice President and Treasurer (G)(H)(I)(J)(K) 2011-present
       
D. R. Schneider 50  President (E) 2009-present
    Senior Vice President, Energy Delivery & Customer Service (B) 2007-2009
    Senior Vice President (C)(D) 2007-2009
    Vice President (B) *-2007
       
L. L. Vespoli 52  Executive Vice President and General Counsel (A)(B)(C)(D)(E)(F) 2008-present
    Executive Vice President and General Counsel (G)(H)(I)(J)(K) 2011-present
    Senior Vice President and General Counsel (A)(B)(C)(D)(E)(F) *-2008
       
H. L. Wagner 59  Vice President, Controller and Chief Accounting Officer (A) *-present
    Vice President and Controller (C)(D)(E)(F) *-present
    Vice President and Controller (G)(I)(J)(K) 2011-present
    Vice President, Controller and Chief Accounting Officer (H) 2011-present
    Vice President, Controller and Chief Accounting Officer (B) 2010-present
    Vice President and Controller (B) *-2010
Executive Officers
Name
Age
Positions Held During Past Five Years
Dates
A. J. Alexander  (A)(G)58President and Chief Executive Officer*-present
W. D. Byrd (B)55Vice President, Corporate Risk & Chief Risk Officer
2007-present
L. M. Cavalier (B)58
Senior Vice President – Human Resources
Vice President
2005-present
*-2005
M. T. Clark (A)(B)(C)(D)(F)(G)59
Executive Vice President and Chief Financial Officer
Executive Vice President – Strategic Planning & Operations
Senior Vice President – Strategic Planning & Operations
2009-present
2008-2009
*-2008
D. S. Elliott (B)(D)55President – Pennsylvania Operations2005-present
Executive Vice President2005-present
Senior Vice President*-2005
R. R. Grigg (A)(B)(C)(D)(H)61
Executive Vice President and President-FirstEnergy Utilities
Executive Vice President and Chief Operating Officer
2008-present
*-2008
J. J. Hagan (G)59
President and Chief Nuclear Officer
Senior Vice President and Chief Operating Officer
Senior Vice President
2007-present
2005-2007
*-2005
C. E. Jones (B)(C)(D)(I)54
Senior Vice President – Energy Delivery & Customer Service
President – FirstEnergy Solutions
Senior Vice President – Energy Delivery & Customer Service
2009-present
2007-2009
*-2007
C. D. Lasky (F)47Vice President – Fossil Operations2008-present
Vice President – Fossil Operations & Air Quality Compliance2007-2008
Vice President*-2007
G. R. Leidich (A)(B)59Executive Vice President & President – FirstEnergy Generation2008-present
Senior Vice President – Operations (B)
President and Chief Nuclear Officer (G)
2007-2008
*-2007
D. C. Luff (B)62Senior Vice President – Governmental Affairs2007-present
Vice President*-2007
D. M. Lynch (E)55
President – JCP&L
Regional President
2009-present
*-2009
J. F. Pearson (A)(B)(C)(D)(F)(G)55Vice President and Treasurer2006-present
Treasurer
Group Controller – Strategic Planning and Operations
2005-2006
*-2005
D. R. Schneider (F)48
President
Senior Vice President – Energy Delivery & Customer Service (B)
Vice President (B)
Vice President (F)
2009-present
2007-2009
2006-2007
*-2006
L.L. Vespoli (A)(B)(C)(D)(F)(G)50Executive Vice President and General Counsel2008-present
Senior Vice President and General Counsel*-2008
H. L. Wagner (A)(B)(C)(D)(F)(G)57Vice President, Controller and Chief Accounting Officer*-present


(A) Denotes executive officer of FE Corp.(F) Denotes executive officer of FES.
(B) Denotes executive officer of FE Service(G) Denotes executive officer of FENOC.
(C) Denotes executive officers of OE, CEI and TE.(H) Retiring March 31, 2010.
(D) Denotes executive officer of Met-Ed, Penelec and Penn.
(E) Denotes executive officer of JCP&L
(I)   Named Senior Vice President and President,
       FirstEnergy Utilities, effective April 1, 2010
* Indicates position held at least since January 1, 2005.2007(E) Denotes executive officer of FES(J) Denotes executive officer of MP, PE and WP
(A) Denotes executive officer of FE(F) Denotes executive officer of FENOC(K) Denotes executive officer of TrAIL
(B) Denotes executive officer of FESC(G) Denotes executive officer of AE(L) Position effective January 1, 2012
(C) Denotes executive officer of OE, CEI and TE(H) Denotes executive officer of AESC(M) Retired on December 31, 2011
(D) Denotes executive officer of Met-Ed, Penelec and Penn(I) Denotes executive officer of AGC


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Employees

As of December 31, 2009,2011, FirstEnergy’s subsidiaries had a total of 13,37917,257 employees located in the United States as follows:

 Total  Bargaining Unit 
 
Employees
  Employees 
Total
Employees
 
Bargaining
Unit
Employees
FESC  2,910   284 2,975
 293
AESC(1)
3,971
 1,177
OE  1,191   709 1,222
 714
CEI  873   584 897
 608
TE  396   294 390
 290
Penn  200   147 204
 153
JCP&L  1,432   1,092 1,413
 1,090
Met-Ed  706   509 678
 488
Penelec  902   632 896
 638
ATSI  38   - 38
 —
FES  247   - 273
 —
FGCO  1,784   1,154 1,652
 1,061
FENOC  2,700   1,014 2,648
 957
Total  13,379   6,419 17,257
 7,469

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

(1)
AESC employs substantially all of the former Allegheny personnel who provide services to AE and its subsidiaries, including AE Supply, AGC, MP, PE, WP and TrAIL.
FirstEnergy Web Site

Each of the registrant’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are also made available free of charge on or through FirstEnergy’s internet Web site at www.firstenergycorp.com. These reports are posted on the Web site as soon as reasonably practicable after they are electronically filed with the SEC. Additionally, we routinely post important information on our Web site and recognize our Web site isas a channel of distribution to reach public investors and as a means of disclosing material non-public information for complying with disclosure obligations under SECthe SEC's Regulation FD. Information contained on FirstEnergy’s Web site shall not be deemed incorporated into, or to be part of, this report.

In accordance with SEC rules, FirstEnergy will include disclosure of any amendment or waiver to its Code of Ethics or a provision of that Code on its Internet Web site within four business days following the date of any such amendment or waiver.
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ITEM 1A. RISK FACTORS

ITEM 1A.RISK FACTORS
We operate in a business environment that involves significant risks, many of which are beyond our control. Management of each Registrant regularly evaluates the most significant risks of the Registrant’s businesses and reviews those risks with the FirstEnergy Board of Directors or appropriate Committees of the Board. The following risk factors and all other information contained in this report should be considered carefully when evaluating FirstEnergy and our subsidiaries. These risk factors could affect our financial results and cause such results to differ materially from those expressed in any forward-looking statements made by or on behalf of us. Below, we have identified risks we currently consider material. However, our business, financial condition, cash flows or results of operations could be affected materially and adversely by additional risks not currently known to us or that we deem immaterial at this time. Additional information on risk factors is included in "Item“Item 1. Business"Business” and "Item“Item 7. Management'sManagement’s Discussion and Analysis of Financial ConditionRegistrant and Results of Operations"Subsidiaries” and in other sections of this Form 10-K that include forward-looking and other statements involving risks and uncertainties that could impact our business and financial results.

Risks Related to Business Operations

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

Operation of generation, transmission and distribution facilities involves risk, including the risk of potential breakdown or failure of equipment or processes due to aging infrastructure, fuel supply or transportation disruptions, accidents, labor disputes or work stoppages by employees, acts of terrorism or sabotage, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions resulting from environmental limitations and governmental interventions, and performance below expected levels. In addition, weather-related incidents and other natural disasters can disrupt generation, transmission and distribution delivery systems. Because our transmission facilities are interconnected with those of third parties, the operation of our facilities could be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties.


27


Operation of our power plants below expected capacity levels could result in lost revenues and increased expenses, including higher operating and maintenance costs.costs, purchased power costs and capital requirements. Unplanned outages of generating units and extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of our business. Unplanned outages typically increase our operation and maintenance expenses and may reduce our revenues as a result of selling fewer MWH or may require us to incur significant costs as a result of operating our higher cost units or obtaining replacement power from third parties in the open market to satisfy our forward power sales obligations. Moreover, if we were unable to perform under contractual obligations, penalties or liability for damages could result.
FES, FGCO and the Ohio Companies are exposed to losses under their applicable sale-leaseback arrangements for generating facilities upon the occurrence of certain contingent events that could render those facilities worthless. Although we believe these types of events are unlikely to occur, FES, FGCO and the Ohio Companies have a maximum exposure to loss under those provisions of approximately $1.3$1.4 billion for FES, $800$606 million for OE and an aggregate of $700$587 million for TE and CEI as co-lessees.

We remain obligated to provide safe and reliable service to customers within our franchised service territories. Meeting this commitment requires the expenditure of significant capital resources. Failure to provide safe and reliable service and failure to meet regulatory reliability standards due to a number of factors, including, but not limited to, equipment failure and weather, could adversely affect our operating results through reduced revenues and increased capital and operating costs and the imposition of penalties/fines or other adverse regulatory outcomes.

Changes in Commodity Prices Could Adversely Affect Our Profit Margins
We purchase and sell electricity in the competitive wholesale and retail markets. Increases in the costs of fuel for our generation facilities (particularly coal, uranium and natural gas) can affect our profit margins. Changes in the market price of electricity, which are affected by changes in other commodity costs and other factors, may impact our results of operations and financial position by increasing the amount we pay to purchase power to supply PLRPOLR and default service obligations in Ohio and Pennsylvania.the states we do business. In addition, the weakening global economy could lead to lower international demand for coal, oil and natural gas, which may lower fossil fuel prices and put downward pressure on electricity prices

prices.
Electricity and fuel prices may fluctuate substantially over relatively short periods of time for a variety of reasons, including:

changing weather conditions or seasonality;
▪changing weather conditions or seasonality;
changes in electricity usage by our customers;

illiquidity and credit worthiness of participants in wholesale power and other markets;
▪changes in electricity usage by our customers;
transmission congestion or transportation constraints, inoperability or inefficiencies;

availability of competitively priced alternative energy sources;
▪illiquidity in wholesale power and other markets;
changes in supply and demand for energy commodities;
changes in power production capacity;
outages at our power production facilities or those of our competitors;
27changes in production and storage levels of natural gas, lignite, coal, crude oil and refined products;
changes in legislation and regulation; and
▪transmission congestion or transportation constraints, inoperability or inefficiencies;

▪availability of competitively priced alternative energy sources;

▪changes in supply and demand for energy commodities;

▪changes in power production capacity;

▪outages at our power production facilities or those of our competitors;

▪changes in production and storage levels of natural gas, lignite, coal, crude oil and refined products;

▪changes in legislation and regulation; and

▪natural disasters, wars, acts of sabotage, terrorist acts, embargoes and other catastrophic events.

We Are Exposed to Operational, Price and Credit Risks Associated With Selling and Marketing Products in the Power Markets That We Do Not Always Completely Hedge Against

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

We attempt to mitigate risks associated with satisfying our contractual power sales arrangements by reserving generation capacity to deliver electricity to satisfy our net firm sales contracts and, when necessary, by purchasing firm transmission service. We also routinely enter into contracts, such as fuel and power purchase and sale commitments, to hedge our exposure to fuel requirements and other energy-related commodities. We may not, however, hedge the entire exposure of our operations from commodity price


28


volatility. To the extent we do not hedge against commodity price volatility, our results of operations and financial position could be negatively affected.

The Use of Derivative Contracts by Us to Mitigate Risks Could Result in Financial Losses That May Negatively Impact ourOur Financial Results

We use a variety of non-derivative and derivative instruments, such as swaps, options, futures and forwards, to manage our commodity and financial market risks. In the absence of actively quoted market prices and pricing information from external sources, the valuation of some of these derivative instruments involves management'smanagement’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of some of these contracts. Also, we could recognize financial losses as a result of volatility in the market values of these contracts or if a counterparty fails to perform.

Financial Derivatives Reforms Could Increase Our Liquidity Needs and Collateral Costs and Impose Additional Regulatory Burdens
In July 2010, federal legislation was enacted to reform financial markets that significantly alter how OTC derivatives are regulated. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank) increased regulatory oversight of OTC derivatives, including (1) requiring standardized OTC derivatives to be traded on registered exchanges regulated by the CFTC, (2) imposing new and potentially higher capital and margin requirements and (3) authorizing the establishment of overall volume and position limits. The law gives the CFTC authority to exempt companies that participate in the swap market as “end users” for hedging purposes which could reduce, but not eliminate, the applicability of these measures to us. These requirements could cause our OTC transactions to be more costly and have an adverse effect on our liquidity due to additional capital requirements. In addition, as these reforms aim to standardize OTC products it could limit the effectiveness of our hedging programs because we would have less ability to tailor OTC derivatives to match the precise risk we are seeking to protect.
We rely on the OTC derivative markets as part of our program to hedge the price risk associated with our power portfolio. The effect on our operations of this legislation will depend in part on whether we are determined to be a swap dealer, a major swap participant or a qualifying end-user through a self-identification process, based on the meaning of those terms to be established in the final rules. If we are determined to be a swap dealer or a major swap participant, we will be required to register with the CFTC and execute most bilateral OTC derivative transactions through an exchange or central clearinghouse. This requirement could require us to commit substantial additional capital to cover increases in collateral costs associated with margin requirements of the major exchanges. We would also be required to comply with increased reporting and record-keeping requirements and follow CFTC-specified business conduct standards, and adhere to position limits in a potentially broad range of energy commodities.
Even if we are not determined to be a swap dealer or a major swap participant, we will be required to comply with additional regulatory obligations under Dodd-Frank, which includes some reporting requirements, clearing some additional transactions that we would otherwise enter into over-the-counter, and having to adhere to position limits. Also, the total burden that the rules could impose on all market participants could cause liquidity in the bilateral OTC swap market to decrease substantially. The new rules could impede our ability to meet our hedge targets in a cost-effective manner. FirstEnergy cannot predict the ultimate outcome that Dodd-Frank will have on its results of operations, cash flows or financial position.
Our Risk Management Policies Relating to Energy and Fuel Prices, and Counterparty Credit, Are by Their Very Nature Risk Related, and We Could Suffer Economic Losses Despite Such Policies

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

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Our risk management activities, including our power sales agreements with counterparties, rely on projections that depend heavily on judgments and assumptions by management of factors such as future market prices and demand for power and other energy-related commodities. These factors become more difficult to predict and the calculations become less reliable the further into the future these estimates are made. Even when our policies and procedures are followed and decisions are made based on these estimates, results of operations may be diminished if the judgments and assumptions underlying those calculations prove to be inaccurate.

We also face credit risks from parties with whom we contract who could default in their performance, in which cases we could be forced to sell our power into a lower-priced market or make purchases in a higher-priced market than existed at the time of executing


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the contract. Although we have established risk management policies and programs, including credit policies to evaluate counterparty credit risk, there can be no assurance that we will be able to fully meet our obligations, that we will not be required to pay damages for failure to perform or that we will not experience counterparty non-performance or that we will collect for voided contracts. If counterparties to these arrangements fail to perform, we may be forced to enter into alternative hedging arrangements or honor underlying commitments at then-current market prices. In that event, our financial results could be adversely affected.

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

We are subject to the risks of nuclear generation, including but not limited to the following:

the potential harmful effects on the environment and human health resulting from unplanned radiological releases associated with the operation of our nuclear facilities and the storage, handling and disposal of radioactive materials;
▪the potential harmful effects on the environment and human health resulting from unplanned radiological releases associated with the operation of our nuclear facilities and the storage, handling and disposal of radioactive materials;
limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with our nuclear operations or those of others in the United States;

uncertainties with respect to contingencies and assessments if insurance coverage is inadequate; and
▪limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with our nuclear operations or those of others in the United States;

▪uncertainties with respect to contingencies and assessments if insurance coverage is inadequate; and

▪uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed operation including increases in minimum funding requirements or costs of completion.

The NRC has broad authority under federal law to impose licensing security and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines and/or shut down a unit, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants, including ours. Also, a serious nuclear incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or relicensing of any domestic nuclear unit.

Our nuclear facilities are insured under NEIL policies issued for each plant. Under these policies, up to $2.8 billion of insurance coverage is provided for property damage and decontamination and decommissioning costs. We have also obtained approximately $2.0 billion of insurance coverage for replacement power costs. Under these policies, we can be assessed a maximum of approximately $79 million for incidents at any covered nuclear facility occurring during a policy year that are See "Potential NRC Regulation in excess of accumulated funds availableResponse to the insurerIncident at Japan's Fukushima Daiichi Nuclear Plant Could Adversely Effect Our Business and Financial Condition" below and Note 16, Commitments, Guarantees and Contingencies - Environmental Matters of the Combined Notes to the Consolidated Financial Statements.
We Have a Significant Percentage of Coal-Fired Generation Capacity Which Exposes us to Risk from Regulations Relating to Coal and Coal Combustion Residuals
Approximately 65% of FirstEnergy's generation fleet capacity is coal-fired. Historically, coal-fired generating plants face greater exposure to the costs of complying with federal, state and local environmental statutes, rules and regulations relating to emissions of SO2 and NOx. In addition, the MATS established coal-fired emission standards for paying losses.

The Price-Anderson Act limits the public liability that can be assessed with respectmercury, hydrochloric acid and various metals effective in April 2015, proposed coal combustion residual regulations include an option to reclassify coal ash as a nuclear power planthazardous waste, and there are currently a number of federal, state and international initiatives under consideration to, $12.5 billion (assuming 104 units licensed to operateamong other things, require reductions in GHG emissions. These legal requirements and initiatives could require substantial additional costs, extensive mitigation efforts and, in the United States)case of GHG requirements, could raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for a single nuclear incident, which amount is covered by:  (i) private insurance amountingnew and existing electric generation facilities. Failure to $300.0 million; and (ii) $12.2 billion provided by an industry retrospective rating plan. Undercomply with any such retrospective rating plan,existing or future legal requirements may also result in the eventassessment of a nuclear incident atfines and penalties. Significant resources also may be expended to defend against allegations of violations of any unit in the United States resulting in losses in excess of private insurance, up to $117.5 million (but not more than $17.5 million per year) must be contributed for each nuclear unit licensed to operate in the country by the licensees thereof to cover liabilities arising out of the incident. Our maximum potential exposure under these provisions would be $470.0 million per incident but not more than $70.0 million in any one year.

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such requirements.
Capital Market Performance and Other Changes May Decrease the Value of Decommissioning Trust Fund, Pension Fund Assets, Decommissioning and Other Trust Funds Which Then Could Require Significant Additional Funding

Our financial statements reflect the values of the assets held in trust to satisfy our obligations to decommission our nuclear generation facilities and under pension and other post-retirementpostemployment benefit plans. The value of certain of the assets held in these trusts do not have readily determinable market values. Changes in the estimates and assumptions inherent in the value of these assets could affect the value of the trusts. If the value of the assets held by the trusts declines by a material amount, our funding obligation to the trusts could materially increase. The recent disruption in the capital markets and its effects on particular businesses and the economy in general also affects the values of the assets that are held in trust to satisfy future obligations to decommission our nuclear plants, to pay pensions to our retired employees and to pay other funded obligations. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. Forecasting investment earnings and costs to decommission nuclear generating stations, to pay future pensions and other obligations requires significant judgment, and actual results may differ significantly from current estimates. Capital market conditions that generate investment losses or greater liability levelsincrease the present value of liabilities can negatively impact our results of operations and financial position.

We Could be Subject to Higher Costs and/or Penalties Related to Mandatory Reliability Standards Set by NERC/FERC or Changes in the Rules of Organized Markets and the States in Which we doWe Do Business
As a result of the EPACT, owners, operators, and users of the bulk electric system are subject to mandatory reliability standards promulgated by the NERC and approved by FERC as well as mandatory reliability standards and energy efficiency requirements imposed by each of the states in which we operate. The standards are based on the functions that need to be performed to ensure that the bulk electric system operates reliably. Compliance with modified or new reliability standards may subject us to higher operating costs and/or increased capital expenditures. If we were found not to be in compliance with the mandatory reliability


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standards, we could be subject to sanctions, including substantial monetary penalties.

Reliability standards that were historically subject to voluntary compliance are now mandatory and could subject us to potential civil penalties for violations which could negatively impact our business. The FERC can now impose penalties of $1.0 million per day for failure to comply with these mandatory electric reliability standards.

In addition to direct regulation by the FERC and the states, we are also subject to rules and terms of participation imposed and administered by various RTOs and ISOs. Although these entities are themselves ultimately regulated by the FERC, they can impose rules, restrictions and terms of service that are quasi-regulatory in nature and can have a material adverse impact on our business. For example, the independent market monitors of ISOs and RTOs may impose bidding and scheduling rules to curb the potential exercise of market power and to ensure the market functions. Such actions may materially affect our ability to sell, and the price we receive for, our energy and capacity. In addition, the RTOs may direct our transmission owning affiliates to build new transmission facilities to meet the reliability requirements of the RTO or to provide new or expanded transmission service under the RTO tariffs.

We Rely on Transmission and Distribution Assets That We Do Not Own or Control to Deliver Our Wholesale Electricity. If Transmission is Disrupted, Including Our Own Transmission, or Not Operated Efficiently, or if Capacity is Inadequate, Our Ability to Sell and Deliver Power May Be Hindered

We depend on transmission and distribution facilities owned and operated by utilities and other energy companies to deliver the electricity we sell. If transmission is disrupted (as a result of weather, natural disasters or other reasons) or not operated efficiently by independent system operators,ISOs, in applicable markets, or if capacity is inadequate, our ability to sell and deliver products and satisfy our contractual obligations may be hindered, or we may be unable to sell products on the most favorable terms. In addition, in certain of the markets in which we operate, we may be required to pay for congestion costs if we schedule delivery of power between congestion zones during periods of high demand. If we are unable to hedge or recover for such congestion costs in retail rates, our financial results could be adversely affected.
Demand for electricity within our utilities’Utilities’ service areas could stress available transmission capacity requiring alternative routing or curtailing electricity usage that may increase operating costs or reduce revenues with adverse impacts to our results of operations. In addition, as with all utilities, potential concerns over transmission capacity could result in MISO, PJM or the FERC requiring us to upgrade or expand our transmission system, requiring additional capital expenditures.

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

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Disruptions in Our Fuel Supplies or Changes in Our Fuel Needs Could Occur, Which Could Adversely Affect Our Ability to Operate Our Generation Facilities andor Impact Financial Results

We purchase fuel from a number of suppliers. The lack of availability of fuel at expected prices, or a disruption in the delivery of fuel which exceeds the duration of our on-site fuel inventories, including disruptions as a result of weather, increased transportation costs or other difficulties, labor relations or environmental or other regulations affecting our fuel suppliers, could cause an adverse impact on our ability to operate our facilities, possibly resulting in lower sales and/or higher costs and thereby adversely affect our results of operations. Operation of our coal-fired generation facilities is highly dependent on our ability to procure coal. Although weWe have long-term contracts in place for a majority of our coal and coal transportation needs, power generators inneeds. We may from time to time enter into new, or renegotiate certain of these contracts, but can provide no assurance that such contracts will be negotiated or renegotiated, as the Midwest and the Northeast have experienced significant pressurescase may be, on available coal supplies that are either transportationsatisfactory terms, or supply related. Ifat all. In addition, if prices for physical delivery are unfavorable, our financial condition, results of operations and cash flows could be materially adversely affected.

Temperature Variations as well as Weather Conditions or other Natural Disasters Could Have a Negative Impact on Our Results of Operations and Demand Significantly Below or Above ourOur Forecasts Could Adversely Affect ourOur Energy Margins

Weather conditions directly influence the demand for electric power. Demand for power generally peaks during the summer and winter months, with market prices also typically peaking at that time. Overall operating results may fluctuate based on weather conditions. In addition, we have historically sold less power, and consequently received less revenue, when weather conditions are milder. Severe weather, such as tornadoes, hurricanes, ice or snow storms,snowstorms, or droughts or other natural disasters, may cause outages and property damage that may require us to incur additional costs that are generally not insured and that may not be recoverable from customers. The effect of the failure of our facilities to operate as planned under these conditions would be particularly burdensome during a peak demand period.

Customer demand could change as a result of severe weather conditions or other circumstances over which we have no control. We satisfy our electricity supply obligations through a portfolio approach of providing electricity from our generation assets, contractual relationships and market purchases. A significant increase in demand could adversely affect our energy margins if we are required under the terms of the default service tariffs to provide the energy supply to fulfill this increased demand at cappedfixed rates, which we expect would remain below the


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wholesale prices at which we would have to purchase the additional supply if needed or, if we had available capacity, the prices at which we could otherwise sell the additional supply. Accordingly, any significant change in demand could have a material adverse effect on our results of operations and financial position.

We Are Subject to Financial Performance Risks Related to Regional and General Economic Cycles and also Related to Heavy Manufacturing Industries such as Automotive and Steel

Our business follows the economic cyclescycles. Economic conditions are a determinant of our customers. As our retail strategy is centered around the sale of output from our generating plants generally where that power will reach, therefore, we are more directly impacted by the economic conditions in our primary markets (i.e., Western Pennsylvania, Ohio,  Maryland, New Jersey, Michigan and Illinois).  Declines in demand for electricity as a result of a regional economic downturn would be expected to reduce overalland declines in the demand for electricity sales andwill reduce our revenues. A decreaseThe regional economy in electric generation sales volume has been, andwhich our Utilities operate is expected to continue to be, influenced by circumstancesconditions in automotive, steel and other heavy industries.

industries and as these conditions change, our revenues will be impacted. Additionally, the primary market areas of our Competitive Energy Services segment overlap, to a large degree, with our Utilities' territories and hence its revenues are impacted by the same economic conditions.
Increases in Customer Electric Rates and the Impact of the Economic DownturnUncertainty May Lead to a Greater Amount of Uncollectible Customer Accounts
Our operations are impacted by the economic conditions in our service territories and those conditions could negatively impact the rate of delinquent customer accounts and our collections of accounts receivable which could adversely impact our financial condition, results of operations and cash flows.
TheWe May Recognize Impairments of Recorded Goodwill or of One or MoreSome of Our Operating Subsidiaries May Become Impaired,Long-Lived Assets, Which Would Result in Write-Offs of the Impaired Amounts
 
Goodwill could become impaired at one or more of our operating subsidiaries. In addition, one or more of our long-lived assets could become impaired. The actual timing and amounts of any goodwill impairments in future years would depend on many uncertainties,factors, including changing interest rates, utility sector market performance, our capital structure, market prices for power, results of future rate proceedings, operating and capital expenditure requirements, the value of comparable utility acquisitions, environmental regulations and other factors.

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

We must find ways to retainbalance the retention of our aging skilled workforce while recruiting new talent to mitigate losses in critical knowledge and skills due to retirements. Mitigating these risks could require additional financial commitments.

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

We continually focus on limiting, and reducing where possible, our operation and maintenance expenses. However, we expect cost pressures could increase as we continue to implement our retail sales strategy. We expect to continue to face increased cost pressures in the areas of health care and pension costs. We have experienced significant health care cost inflation in the last few years, and we expect our cash outlay for health care costs, including prescription drug coverage, to continue to increase despite measures that we have taken and expect to take requiring employees and retirees to bear a higher portion of the costs of their health care benefits. The measurement of our expected future health care and pension obligations and costs is highly dependent on a variety of assumptions, many of which relate to factors beyond our control. These assumptions include investment returns, interest rates, health care cost trends, benefit design changes, salary increases, the demographics of plan participants and regulatory requirements. If actual results differ materially from our assumptions, our costs could be significantly increased.

Our Results May be Adversely Affected by the Volatility in Pension and OPEB Expenses.
Our BusinessEffective in 2011, FirstEnergy elected to change its method of recognizing actuarial gains and losses of its pension and OPEB plans. This change will result in the recognition of net actuarial gains or losses, without deferral, in the fourth quarter of each year and whenever a plan is Subjectdetermined to qualify for a remeasurement, may result in greater volatility in pension and OPEB expenses and may materially impact our results of operations under GAAP. For additional information, see Note 1, Organization, Basis of Presentation and Significant Accounting Policies of the Combined Notes to the Risk that Sensitive Customer Data May be Compromised,Consolidated Financial Statements.
Security Breaches, Including Cyber Security Breaches, and Other Disruptions Could Compromise Critical and Proprietary Information and Expose Us to Liability, Which Could Result in an Adverse ImpactWould Cause our Business and Reputation to Our Reputation and/or Results of OperationsSuffer.

Our business requires access to sensitive customer data, including personal and credit information, inIn the ordinary course of business. A security breach may occur, despiteour business, we store sensitive data, intellectual property and proprietary information regarding our business, employees, customers, suppliers and business partners in our data centers and on our networks. The secure maintenance of this information is critical to our operations. Despite security measures takenwe have employed with respect to this information, our information technology and infrastructure may be vulnerable to attacks by ushackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and requiredthe information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of vendors. If a significantinformation could result in legal claims or widely publicized breach occurred,proceedings and regulatory penalties. It could also disrupt our business operations and damage our reputation, may be adversely affected, customer confidence may be diminished, or we may become subject to legal claims, fines or penalties, any of which could have a negative impact onadversely affect our business and/or results of operations.business.


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Acts of War or Terrorism Could Negatively Impact Our Business

The possibility that our infrastructure, such as electric generation, transmission and distribution facilities, or that of an interconnected company, could be direct targets of, or indirect casualties of, an act of war or terrorism, could result in disruption of our ability to generate, purchase, transmit or distribute electricity. Any such disruption could result in a decrease in revenues and additional costs to purchase electricity and to replace or repair our assets, which could have a material adverse impact on our results of operations and financial condition.

Capital Improvements and Construction Projects May Not be Completed Within Forecasted Budget, Schedule or Scope Parameters

Our business plan calls for extensive capital investments, including the installation of environmental control equipment, as well as other initiatives.investments. We may be exposed to the risk of substantial price increases in the costs of labor and materials used in construction. We have engagedengage numerous contractors and enteredenter into a large number of agreements to acquire the necessary materials and/or obtain the required construction-related services. As a result, we are also exposed to the risk that these contractors and other counterparties could breach their obligations to us. Such risk could include our contractors’ inabilities to procure sufficient skilled labor as well as potential work stoppages by that labor force. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices, with resulting delays in those and other projects. Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than these mitigation provisions. This could have negative financial impacts such as incurring losses or delays in completing construction projects.

Changes in Technology May Significantly Affect Our Generation Business by Making Our Generating Facilities Less Competitive

We primarily generate electricity at large central facilities. This method results in economies of scale and lower costs than newer technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells. It is possible that advances in technologies will reduce their costs to levels that are equal to or below that of most central station electricity production, which could have a material adverse effect on our results of operations.

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We May Acquire Assets That Could Present Unanticipated Issues for ourOur Business in the Future, Which Could Adversely Affect Our Ability to Realize Anticipated Benefits of Those Acquisitions

Asset acquisitions involve a number of risks and challenges, including: management attention; integration with existing assets; difficulty in evaluating the requirements associated with the assets prior to acquisition, operating costs, potential environmental and other liabilities, and other factors beyond our control; and an increase in our expenses and working capital requirements. Any of these factors could adversely affect our ability to achieve anticipated levels of cash flows or realize other anticipated benefits from any such asset acquisition.

Ability of Certain FirstEnergy Companies to Meet Their Obligations to or on behalf of Other FirstEnergy Companies

or their Affiliates
Certain of the FirstEnergy companies have obligations to other FirstEnergy companies because of transactions involving energy, coal, other commodities, services and because of hedging transactions. If one FirstEnergy entity failed to perform under any of these arrangements, other FirstEnergy entities could incur losses. Their results of operations, financial position, or liquidity could be adversely affected, resulting in the nondefaulting FirstEnergy entity being unable to meet its obligations to unrelated third parties. Our hedging activities are generally undertaken with a view to overall FirstEnergy exposures. Some FirstEnergy companies may therefore be more or less hedged than if they were to engage in such transactions alone. Also, some companies affiliated with FirstEnergy also provide guarantees to third party creditors on behalf of other FirstEnergy affiliates under transactions of the type described above or under financing transactions. Any failure to perform under such a guarantee by the affiliated FirstEnergy guarantor company or under the underlying transaction by the FirstEnergy company on whose behalf the guarantee was issued could have similar adverse impacts on one or both FirstEnergy companies or their affiliates.
Energy Companies are Subject to Adverse Publicity Which Make Them Vulnerable to Negative Regulatory and Legislative Outcomes

Risks Associated With our Proposed Merger With Allegheny

We May be Unable to ObtainEnergy companies, including FirstEnergy's utility subsidiaries, have been the Approvals Required to Complete our Merger with Allegheny or, in Order to do so, the Combined Company May be Required to Comply With Material Restrictions or Conditions.

On February 11, 2010, we announced the executionsubject of a merger agreement with Allegheny. Before the merger may be completed, shareholder approval will have to be obtained by us and by Allegheny. In addition, various filings must be made with the FERC and various state utility, regulatory, antitrust and other authorities in the United States. These governmental authorities may impose conditionscriticism focused on the completion,reliability of their distribution services and the speed with which they are able to respond to power outages, such as those caused by storm damage. Adverse publicity of this nature, or require changes to the terms, of the merger, including restrictions or conditions on the business, operations, or financial performance of the combined company following completion of the merger. These conditions or changes could have the effect of delaying completion of the merger or imposing additional costs on or limiting the revenues of the combined company following the merger, which could have a material adverse effect on the financial results of the combined companypublicity associated with our nuclear and/or coal-fired facilities may cause either us or Allegheny to abandon the merger.less favorable legislative and regulatory outcomes.

If Completed, Our Merger with AlleghenyAE May Not Achieve Its Intended Results.

We and Allegheny entered into the merger agreement with AE with the expectation that the merger would result in various benefits, including, among other things, cost savings and operating efficiencies relating to both the regulated utility operationsbusiness and the generationunregulated competitive business. AchievingOur ability to achieve the anticipated benefits of the merger is subject to a number of uncertainties, including whether the business and information systems of Allegheny isare integrated in an efficient and effective manner. Failure to achieve these anticipated benefits could result in increased costs, decreases in the amount of expected revenues generated by the combined companyus and diversion of management's time and energy and could have an adverse effect on the combined company'sour business, financial results and prospects.

We Will be Subject to Business Uncertainties See Part II, Item 7, Management's Discussion and Contractual Restrictions While the Merger with Allegheny is Pending That Could Adversely Affect Our Financial Results.Analysis of Registrant and Subsidiaries for additional information.


Uncertainty about the effect of the merger with Allegheny on employees and customers may have an adverse effect on us. Although we intend to take steps designed to reduce any adverse effects, these uncertainties may impair our ability to attract, retain and motivate key personnel until the merger is completed and for a period of time thereafter, and could cause customers, suppliers and others that deal with us to seek to change existing business relationships.33

Employee retention and recruitment may be particularly challenging prior to the completion of the merger, as employees and prospective employees may experience uncertainty about their future roles with the combined company. If, despite our retention and recruiting efforts, key employees depart or fail to accept employment with us because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company, our financial results could be affected.

The pursuit of the merger and the preparation for the integration of Allegheny into our company may place a significant burden on management and internal resources. The diversion of management attention away from day-to-day business concerns and any difficulties encountered in the transition and integration process could affect our financial results.

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In addition, the merger agreement restricts us, without Allegheny‘s consent, from making certain acquisitions and taking other specified actions until the merger occurs or the merger agreement terminates. These restrictions may prevent us from pursuing otherwise attractive business opportunities and making other changes to our business prior to completion of the merger or termination of the merger agreement.

Failure to Complete Our Merger with Allegheny Could Negatively Impact Our Stock Price and Our Future Business and Financial Results

If our merger with Allegheny is not completed, our ongoing business and financial results may be adversely affected and we will be subject to a number of risks, including the following:

We may be required, under specified circumstances set forth in the Merger Agreement, to pay Allegheny a termination fee of $350 million and/or Allegheny’s reasonable out-of-pocket transaction expenses up to $45 million;

we will be required to pay costs relating to the merger, including legal, accounting, financial advisory, filing and printing costs, whether or not the merger is completed; and

matters relating to our merger with Allegheny (including integration planning) may require substantial commitments of time and resources by our management, which could otherwise have been devoted to other opportunities that may have been beneficial to us.  

We could also be subject to litigation related to any failure to complete our merger with Allegheny.  If our merger is not completed, these risks may materialize and may adversely affect our business, financial results and stock price. 

Risks Associated With Regulation

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

Our utility subsidiaries currently provide service at rates approved by one or more regulatory commissions. Thus, the rates a utility is allowed to charge may or may not be set to recover its expenses at any given time. Additionally, there may also be a delay between the timing of when costs are incurred and when costs are recovered. For example, we may be unable to timely recover the costs for our energy efficiency investments, expenses and additional capital or lost revenues resulting from the implementation of aggressive energy efficiency programs. While rate regulation is premised on providing an opportunity to earn a reasonable return on invested capital and recovery of operating expenses, there can be no assurance that the applicable regulatory commission will determine that all of our costs have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs in a timely manner.  For example, our utility subsidiaries’ ability to timely recover rates and charges associated with integration of the ATSI footprint into PJM is uncertain.

Regulatory Changes in the Electric Industry, Including a Reversal of, Discontinuance of, or Delay ofImpediment to the Present Trend Toward Competitive Markets, Could Affect Our Competitive Position and Result in Unrecoverable Costs Adversely Affecting Our Business and Results of Operations

As a result of restructuring initiatives, changes in the electric utility business have occurred, and are continuing to take place throughout the United States, including Ohio, Pennsylvania and New Jersey.the states in which we do business. These changes have resulted, and are expected to continue to result, in fundamental alterations in the way utilities conduct their business.

Some states that have deregulated generation service have experienced difficulty in transitioning to market-based pricing. In some instances, state and federal government agencies and other interested parties have made proposals to impose rate cap extensions or otherwise delayimpede market restructuring or even re-regulate areas of these markets that have previously been deregulated. Although we expect wholesale electricity markets to continue to be competitive, proposals to re-regulate our industry may be made, and legislative or other action affecting the electric power restructuring process may cause the process to be delayed, discontinued, restructured or reversed in the states in which we currently, or may in the future, operate. Such delays, discontinuations or reversals of electricity market restructuring in the markets in which we operate could have an adverse impact on our results of operations and financial condition.

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The FERC and the U.S. Congress propose changes from time to time in the structure and conduct of the electric utility industry. If the restructuring, deregulation or re-regulation efforts result in decreased margins or unrecoverable costs, our business and results of operations would be adversely affected. We cannot predict the extent or timing of further efforts to restructure, deregulate or re-regulate our business or the industry.

The Prospect of Rising Rates Could Prompt Legislative or Regulatory Action to Restrict or Control Such Rate Increases. This In Turn Could Create Uncertainty Affecting Planning, Costs and Results of Operations and May Adversely Affect the Utilities’ Ability to Recover Their Costs, Maintain Adequate Liquidity and Address Capital Requirements
Increases in utility rates, such as may follow a period of frozen or capped rates, can generate pressure on legislators and regulators to take steps to control those increases. Such efforts can include some form of rate increase moderation, reduction or freeze. The public discourse and debate can increase uncertainty associated with the regulatory process, the level of rates and revenues, and the ability to recover costs. Such uncertainty restricts flexibility and resources, given the need to plan and ensure available financial resources. Such uncertainty also affects the costs of doing business. Such costs could ultimately reduce liquidity, as suppliers tighten payment terms, and increase costs of financing, as lenders demand increased compensation or collateral security to accept such risks.

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

The FERC granted FES, FGCO and NGCcertain subsidiaries authority to sell electricity at market-based rates. These orders also granted them waivers of certain FERC accounting, record-keeping and reporting requirements. The Utilities also have market-based rate authority. The FERC’s orders that grant this market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that these companies can exercise market power in transmission or generation, create barriers to entry or engage in abusive affiliate transactions. As a condition to the orders granting the generating companies market-based rate authority, every three years they are required to file a market power update to show that they continue to meet the FERC’s standards with respect to generation market power and other criteria used to evaluate whether entities qualify for market-based rates. FES, FGCO, NGC and the Utilities renewed this authority for PJM in 2008 and MISO in 2009. FES, FGCO, NGC and the Utilities must file to renew this authority for PJM in 2010.  If any of these companies were to lose their market-based rate authority, they would be required to obtain the FERC’s acceptance to sell power at cost-based rates. FES, FGCO and NGC could also lose their waivers, and become subject to the accounting, record-keeping and reporting requirements that are imposed on utilities with cost-based rate schedules.

There Are Uncertainties Relating to Our Participation in Regional Transmission Organizations (RTOs)

RTOs
RTO rules could affect our ability to sell power produced by our generating facilities to users in certain markets due to transmission


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constraints and attendant congestion costs. The prices in day-ahead and real-time energy markets and RTO capacity markets have been subject to price volatility. Administrative costs imposed by RTOs, including the cost of administering energy markets, have also increased. The rules governing the various regional power markets may also change from time to time, which could affect our costs or revenues. To the degree we incur significant additional fees and increased costs to participate in an RTO, and we are limited with respect to recovery of such costs from retail customers, we may suffer financial harm. While RTO rates for transmission service are cost based, our revenues from customers to whom we currently provide transmission services may not reflect all of the administrative and market-related costs imposed under the RTO tariff. In addition, we may be allocated a portion of the cost of transmission facilities built by others due to changes in RTO transmission rate design. Finally, we may be required to expand our transmission system according to decisions made by an RTO rather than our internal planning process. As a member of an RTO, we are subject to certain additional risks, including those associated with the allocation among members of losses caused by unreimbursed defaults of other participants in that RTO’s market and those associated with complaint cases filed against the RTO that may seek refunds of revenues previously earned by its members.

MISO implemented an ancillary services market for operating reserves that would be simultaneously co-optimized with MISO's existing energy markets. The implementation of these and other new market designs has the potential to increase our costs of transmission, costs associated with inefficient generation dispatching, costs of participation in the market and costs associated with estimated payment settlements.

Because it remains unclear which companies will be participating in the various regional power markets, or how RTOs will ultimately develop and operate, or what region they will cover, we cannot fully assess the impact that these power markets or other ongoing RTO developments may have.

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A Significant  Delay  in  or  Challenges  to Various Elements of ATSI’s Consolidation  into  PJM, including but not Limited to, the Intervention of  Parties  to the Regulatory Proceedings, Could have a Negative Impact on Our Results of Operations and Financial Condition

On December 17, 2009, FERC authorized, subject to certain conditions, FirstEnergy to consolidate its transmission assets and operations that currently are located in MISO into PJM; such consolidation to be effective on June 1, 2011. The consolidation will make the transmission assets that are part of ATSI, whose footprint includes the Ohio Companies and Penn, part of PJM. Consolidation on June 1, 2011 will coincide with delivery of power under the next competitive generation procurement process for the Ohio Companies. On December 17, 2009, and after FERC issued the order, ATSI executed and delivered to PJM those legal documents necessary to implement its consolidation into PJM. On December 18, 2009, the Ohio Companies and Penn executed and delivered to PJM those legal documents necessary to follow ATSI into PJM. Currently, ATSI, the Ohio Companies and Penn are expected to consolidate into PJM as planned on June 1, 2011
Certain parties have objected to various aspects of the planned consolidation into PJM.  On September 4, 2009, the PUCO opened a case to take comments from Ohio’s stakeholders regarding the RTO consolidation. Certain parties have intervened and filed comments or protests in the FERC and PUCO dockets regarding particular elements of the proposed RTO consolidation. The disputed elements include, but are not limited to, recovery of integration costs to PJM and exit fees to MISO and cost-allocations of transmission upgrades that originate under the PJM and MISO tariffs. A ruling by FERC or the PUCO or  any other regulator with jurisdiction in favor of one or more of the intervening  or  protesting  parties (and against FirstEnergy) on one or more  of  the  disputed  issues could result in a negative impact on our results of operations and financial condition.

Energy Conservation and Energy Price Increases Could Negatively Impact Our Financial Results

A number of regulatory and legislative bodies have introduced requirements and/or incentives to reduce energy consumption by certain dates.consumption. Conservation programs could impact our financial results in different ways. To the extent conservation resulted in reduced energy demand or significantly slowed the growth in demand, the value of our merchantcompetitive generation and other unregulated business activities could be adversely impacted. While weWe currently have energy efficiency riders in place to recover the cost of these programs either at or near a current recovery timeframe in all threethe states currentlywe operate. In New Jersey, we recover the costs for energy efficiency programs through the SBC. Currently only Ohio allows us to recoverhas provisions for recovery of lost revenues. In our regulated operations, conservation could negatively impact us depending on the regulatory treatment of the associated impacts. Should we be required to invest in conservation measures that result in reduced sales from effective conservation, regulatory lag in adjusting rates for the impact of these measures could have a negative financial impact. We could also be impacted if any future energy price increases result in a decrease in customer usage. Our results could be affected if we are unable to increase our customer’s participation in our energy efficiency programs. We are unable to determine what impact, if any, conservation and increases in energy prices will have on our financial condition or results of operations.

Our Business and Activities are Subject to Extensive Environmental Requirements and Could be Adversely Affected by such Requirements

We plan to retire nine older coal-fired generating plants by September 1, 2012, as a result of a comprehensive review of FirstEnergy's coal-fired generating facilities in light of the MATS rules that were recently finalized and other environmental requirements. We may be forced to shut down other facilities, either temporarily or permanently, if we are unable to comply with certain environmental requirements, or if we make a determination that the expenditures required to comply with such requirements are uneconomical. In fact, we are exposed to the risk that such electric generating plants would not be permitted to continue to operate if pollution control equipment is not installed by prescribed deadlines.

The EPA is Conducting NSR Investigations at a Number of our Generating Plants that We Currently or Formerly Owned, the Results of Which Could Negatively Impact ourOur Results of Operations and Financial Condition

We may be subject to risks in connection with changing or conflicting interpretations of existing laws and regulations, including, for example, the applicability of EPA's NSR programs . Under the CAA, modification of our generation facilities in a manner that results in increased emissions could subject our existing facilities to the far more stringent NSR standards applicable to new facilities.
In August 2009,The EPA has taken the view that many companies, including many energy producers, have been modifying emissions sources in violation of NSR standards in connection with work considered by the companies to be routine maintenance. We are currently involved in litigation and EPA issued a Finding of Violation and NOV alleginginvestigations concerning alleged violations of the CAANSR standards at certain of our existing and Ohio regulations, including the PSD, NNSR,former generating facilities. We intend to vigorously pursue 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. In September 2009, FGCO received an information request pursuant to Section 114(a) of the CAA requesting certain operating and maintenance information and planning information regarding the Eastlake, Lake Shore, Bay Shore and Ashtabula generating plants. On November 3, 2009, FGCO received a letter providing notification that the EPA is evaluating whether certain scheduled maintenance at the Eastlake generating plant may constitute a major modification under the NSR provision of the CAA. On December 23, 2009, FGCO received another information request regarding emission projections for the Eastlake generating plant pursuant to Section 114(a) of the CAA. FGCO intends to comply with the CAA, including EPA’s information requests,defend our position but at this time, iswe are unable to predict the outcome of this matter. A June 2006 finding of violationtheir outcomes. If NSR and NOVsimilar requirements are imposed on our generation facilities, 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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In August 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 directedaddition to the current owner, Reliant Energy, to allow the EPA to determine whether these generating sources are complying with the NSR provisionspossible imposition of the CAA. FirstEnergy intends to fully comply with the Section 114(a) information request  An adverse resultfines, compliance could entail significant capital investments in the above referenced matterspollution control technology, which could have a negativean adverse impact on our business, results of operations, cash flows and financial condition.

For a more complete discussion see Note 16, Commitments, Guarantees and Contingencies - Environmental Matters of the Combined Notes to the Consolidated Financial Statements.
Costs of Compliance with Environmental Laws are Significant, and the Cost of Compliance with Future Environmental Laws, Including Limitations on GHGEmissions, Could Adversely Affect Cash Flow and Profitability

Our operations are subject to extensive federal, state and local environmental statutes, rules and regulations. Compliance with these legal requirements requires us to incur costs for environmental monitoring,among other things, installation and operation of pollution control equipment, emission monitoring and fees, maintenance, upgrading, remediation and permitting at our facilities. These expenditures have been significant in the past and may increase in the future. If the cost of compliance with existing environmental laws and regulations does increase, it could adversely affect our business and results of operations, financial position and cash flows. Moreover, new environmental laws or regulations or changes into existing environmental laws or regulations may materially increase our costs of compliance or accelerate the timing of capital expenditures. Because of the deregulation of generation, we may not directly recover through rates additional costs incurred for such compliance. Our compliance strategy, although reasonably based on available information, may not successfully address future relevant standards and interpretations. If we fail to comply with environmental laws and regulations or


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new interpretations of longstanding requirements, even if caused by factors beyond our control, or new interpretations of longstanding requirements, that failure could result in the assessment of civil or criminal liability and fines. In addition, any alleged violation of environmental laws and regulations may require us to expend significant resources to defend against any such alleged violations.

There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. Environmental advocacy groups, other organizations and some agencies in the United States and elsewhere are focusing considerable attention on carbon dioxide emissions from power generation facilities and their potential role in climate change.  Many states and environmental groups have also challenged certain of the federal laws and regulations relating to air emissions as not being sufficiently strict.  Also, claims have been made alleging that CO2 emissions from power generating facilities constitute a public nuisance under federal and/or state common law.  Private individuals may seek to enforce environmental laws and regulations against us and could allege personal injury or property damage from exposure to hazardous materials.  Recently the courts have begun to acknowledge these claims and may order us to reduce GHG emissions in the future. There is a growing consensus in the United States and globally that GHG emissions are a major cause of global warming and that some form of regulation will be forthcoming at the federal level with respect to GHG emissions (including carbon dioxide)CO2) and such regulation could result in the creation of substantial additional costs in the form of taxes or emission allowances. As a result, it is possible that state and federal regulations will be developed that will impose more stringent limitations on emissions than are currently in effect. In December 2009, the EPA issued an “endangerment and cause or contributing finding” for GHG under the CAA, which will allow the EPA to craft rules that directly regulate GHG.  Although several bills have been introduced at the state and federal level that would compel carbon dioxide emission reductions, none have advanced through the legislature. Due to the uncertainty of control technologies available to reduce greenhouse gasGHG emissions, including CO2, as well as the unknown nature of potential compliance obligations should climate change regulations be enacted, we cannot provide any assurance regarding the potential impacts these future regulations would have on our operations. In addition, any legal obligation that would require us to substantially reduce our emissions could require extensive mitigation efforts and, in the case of carbon dioxide legislation, would raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities. Until specific regulations are promulgated,issued, the impact that any new environmental regulations, voluntary compliance guidelines, enforcement initiatives, or legislation may have on our results of operations, financial condition or liquidity is not determinable.

The EPA’s current CAIR and CAVRFirstEnergy cannot currently estimate the financial impact of certain environmental laws or initiatives including climate change policies, but potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions could require significant reductions beginningcapital and other expenditures or result in 2009 in airchanges to its operations. See Note 16, Commitments, Guarantees and Contingencies - Environmental Matters of the Combined Notes to the Consolidated Financial Statements for a more detailed discussion of the federal, state and international initiatives seeking to reduce emissions of GHG.

We Could be Exposed to Private Rights of Action Seeking Damages Under Various State and Federal Law Theories

Claims have been made against certain energy companies alleging that CO2 emissions from coal-fired power plants and the states have been given substantial discretion in developing their own rules to implement these programs. On December 23, 2008, the United States Court of Appeals for the District of Columbia remanded CAIR to EPA but allowed the current CAIR regulations to remain in effect while EPA works to remedy flaws in the CAIR regulations identified by the court ingenerating facilities constitute a July 11, 2008 opinion.public nuisance under federal and/or state common law. As a result, the ultimate requirements under CAIRprivate individuals may seek to enforce environmental laws and regulations against us and could allege personal injury or property damages. While FirstEnergy is not a party to this litigation, it, and/or one of its subsidiaries, could be known for several years and may differ significantly from the current CAIR regulations. If the EPA significantly changes CAIR, or if the states elect to impose additional requirements on individual units that are already subject to CAIR, the cost of compliance could increase significantly andnamed in actions making similar allegations. An unfavorable ruling in any such case could have an adverse effectimpact on futureour results of operations cash flows and financial condition.condition and could significantly impact our operations.

Our Costs to Comply with Various Recently Adopted EPA Emission Regulations Could be Substantial and Result in Significant Changes to Our Operations

We are required to comply with recently adopted emission regulations. The EPA's final CAMR was vacated by the United States CourtCAIR and CSAPR require reductions of Appeals for the District Court of Columbia on February 8, 2008 becauseNOx and SO2 emissions in two phases, ultimately capping SO2 and NOx emissions in affected states. In July 2011, the EPA failedfinalized the CSAPR (which was stayed in December 2011 pending a decision on various legal challenges) to takereplace CAIR, which remains in effect until CSAPR becomes effective.

Depending on the necessary stepsoutcome of these legal proceedings and how any final rules are ultimately implemented, MP's, FGCO's and AE Supply's future cost of compliance may be substantial and changes to "de-list" coal-fired power plants from its hazardous air pollution program and therefore could not promulgate a cap and trade air emissions reduction program. On OctoberFirstEnergy's operations may result.

Additionally, on December 21, 2009,2011, the EPA opened a 30-day comment period on a proposed consent decree that would obligatefinalized the EPAMATS to propose MACT regulationsestablish emission standards for, among other things, mercury, hydrochloric acid and various metals for electric generating units. The costs associated with MATS, and other hazardous air pollutants by March 16, 2011,environmental laws, is substantial and led to finalize the regulations by November 16, 2011. FGCO’sCompany's recent announcement to retire nine older coal-fired generating units. Depending on how the CSPAR and MATS are ultimately implemented, FirstEnergy's future cost of compliance with MACTsuch regulations may be substantial and could haveadditional changes to FirstEnergy's operations may result. See Note 16, Commitments, Guarantees and Contingencies - Environmental Matters of the Combined Notes to the Consolidated Financial Statements for a material adverse effect on future resultsmore detailed discussion of operations, cash flows and financial condition.the above-referenced EPA regulations.

Various Federal and State Water Quality Regulations May Require Us to Make Material Capital Expenditures
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Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to our generating plants. In addition, Ohio, New Jersey and Pennsylvania have water qualityThe EPA established performance standards applicable to our operations. As provided inunder 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.

There is substantial uncertainty concerning the final form of federal and state regulations to implement Section 316(b) of the Clean Water Act.  On January 26, 2007, the United States Court of Appeals for the Second Circuit remanded back towhich requires the EPA portions of its rulemaking pursuant to Section 316(b). The EPA subsequently suspended its rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimizeestablish performance standards for reducing impacts on fish and shellfish from cooling water intake structures. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue thestructures at certain existing practiceelectric generating plants, specifically, impingement mortality (when aquatic organisms are pinned against screens or other parts of applying their best professional judgment to minimize impacts on fish and shellfish froma cooling water intake structures. On April 1, 2009,system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). In 2011, the Supreme Court of the United States reversed one significant aspect of the Second Circuit Court’s opinion and decided that Section 316(b) ofEPA proposed new regulations under the Clean Water Act authorizeswhich generally require fish impingement to be reduced to a 12% annual average and calls for studies to be conducted at the EPAmajority of our existing generating facilities to compare costs with benefits in determiningassist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic life. FirstEnergy is studying the best technology available for minimizing adverse environmental impact atcost and effectiveness of various control options to divert fish away from its plants' cooling water intake structures.system. Depending on the results of such studies and the EPA's further rulemaking and any final action taken by the states, the future costs of compliance with these standards may require material capital expenditures. See Note 16, Commitments, Guarantees and Contingencies - Environmental Matters of the Combined Notes to the Consolidated Financial Statements for a more detailed discussion of the various federal and state water


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quality regulations listed above.

Compliance with any Coal Combustion Residual Regulations Could Have an Adverse Impact on Our Results of Operations and Financial Condition

We are subject to various federal and state hazardous waste regulations. 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. We may incur significant capital costs to comply with the final regulations.  If either the federal or state final regulations require retrofitting of cooling water intake structures (cooling towers) at any of our power plants, and if installation of such cooling towers is not technically or economically feasible, we may be forced to take actions which could adversely impact our results of operations and financial condition.

Certain fossil-fuel combustion waste products, such as coal ash, have been exempt from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. In February 2009, the EPAhas requested comments from the states on options for regulating coal combustion wastes,residuals, including regulationwhether they should be regulated as hazardous or non-hazardous waste or regulation as a hazardous waste. On December 30, 2009, in an advanced notice of public rulemaking, the

The EPA saidasserted that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry.  Additionalindustry and has proposed two options for additional regulation of fossil-fuelcoal combustion residuals, including the option of regulation as a special waste productsunder the EPA's hazardous waste management program which could have a significant impact on ourthe management, beneficial use and disposal of coal ash and ourcombustion residuals. FirstEnergy's future cost of compliance with any coal combustion residuals regulations that may be issued could increase significantly whichbe substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the EPA or the states. Compliance with those regulations could have a materialan adverse effectimpact on futureour results of operations cash flows and financial condition.

The Physical Risks Associated with Climate Change May Impact Our Results of Operations and Cash Flows.

Physical risks of climate change, such as more frequent or more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, and other related phenomena, could affect some, or all, of our operations. Severe weather or other natural disasters could be destructive, which could result in increased costs, including supply chain costs. An extreme weather event within the Utilities’ service areas can also directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment. Finally, climate change could affect the availability of a secure and economical supply of water in some locations, which is essential for FirstEnergy’s and FES’s continued operation, particularly the cooling of generating units.

Remediation of Environmental Contamination at Current or Formerly Owned Facilities

We are subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we may have generated regardless of whether the liabilities arose before, during or after the time we owned or operated the facilities. Remediation activities associated with our former MGP operations are one source of such costs. We are currently involved in a number of proceedings relating to sites where other hazardous substances have been deposited and may be subject to additional proceedings in the future. We also have current or previous ownership interests in sites associated with the production of gas and the production and delivery of electricity for which we may be liable for additional costs related to investigation, remediation and monitoring of these sites. Citizen groups or others may bring litigation over environmental issues including claims of various types, such as property damage, personal injury, and citizen challenges to compliance decisions on the enforcement of environmental requirements, such as opacity and other air quality standards, which could subject us to penalties, injunctive relief and the cost of litigation. We cannot predict the amount and timing of all future expenditures (including the potential or magnitude of fines or penalties) related to such environmental matters, although we expect that they could be material.
In some cases, a third party who has acquired assets from us has assumed the liability we may otherwise have for environmental matters related to the transferred property. If the transferee fails to discharge the assumed liability or disputes its responsibility, a regulatory authority or injured person could attempt to hold us responsible, and our remedies against the transferee may be limited by the financial resources of the transferee.

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

Although recent court rulings and current conditions have reduced the immediate risk of a negative impact on our operating costs, the uncertainty around CAA programs and requirements continue to be a major concern. We are still required to maintain, either by allocation or purchase, sufficient emission creditsallowances to support our operations in the ordinary course of operating our power generation facilities. These creditsallowances are used to meet our obligations imposed by various applicable environmental laws. If our operational needs require more than our allocated allowances, of emission credits, we may be forced to purchase such creditsallowances on the open market, which could be costly. If we are unable to maintain sufficient emission creditsallowances to match our operational needs, we may have to curtail our operations so as not to exceed our available emission credits,allowances, or install costly new emissions controls. As we use the emissions creditsallowances that we have purchased on the open market, costs associated with such purchases will be recognized as operating expense. If such creditsallowances are available for purchase, but only at significantly higher prices, the purchase of such creditsallowances could materially increase our costs of operations in the affected markets.  Laws and regulations such as CAIR may, and are, being revised and as CAIR is being rewritten it is creating uncertainty in many areas, including but not limited to, the annual NOx emission allowances beyond 2010.

Mandatory Renewable Portfolio Requirements Could Negatively Affect Our Costs

If federal or state legislation mandates the use of renewable and alternative fuel sources, such as wind, solar, biomass and geothermal and such legislation would not also provide for adequate cost recovery, it could result in significant changes in our business, including renewable energy credit purchase costs, purchased power and potentially renewable energy credit costs and capital expenditures. We are unable to predict what impact, if any, these changes may have on our financial condition or results of operations.

We Are and May Become Subject to Legal Claims Arising from the Presence of Asbestos or Other Regulated Substances at Some of our Facilities

We have been named as a defendant in pending asbestos litigation involving multiple plaintiffs and multiple defendants. In addition, asbestos and other regulated substances are, and may continue to be, present at our facilities where suitable alternative materials are not available. We believe that any remaining asbestos at our facilities is contained. The continued presence of asbestos and other regulated substances at these facilities, however, could result in additional actions being brought against us.

The Continuing Availability and Operation of Generating Units is Dependent on Retaining or Renewing the Necessary Licenses, Permits, and Operating Authority from Governmental Entities, Including the NRC


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We are required to have numerous permits, approvals and certificates from the agencies that regulate our business. We believe the necessary permits, approvals and certificates have been obtained for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from future regulatory activities of any of these agencies and we are not assured that any such permits, approvals or certifications will be renewed.
Potential NRC Regulation in Response to the Incident at Japan's Fukushima Daiichi Nuclear Plant Could Adversely Effect Our Business and Financial Condition

As a result of the NRC's investigation of the incident at the Fukushima Daiichi nuclear plant, potential exists for the NRC to promulgate new or revised requirements with respect to nuclear plants located in the United States, which could necessitate additional expenditures at our nuclear plants. For example, as a follow up to the NRC near-term Task Force's review and analysis of the Fukushima Daiichi accident, in January 2012, the NRC released an updated seismic risk model that plant operators must use in performing the seismic reevaluations recommended by the task force. These reevaluations could result in the required implementation of additional mitigation strategies or modifications. It is also possible that the NRC could suspend or otherwise delay pending nuclear relicensing proceedings, including the Davis-Besse relicensing proceeding. The impact of any such regulatory actions could adversely affect FirstEnergy's financial condition or results of operations.
The Physical Risks Associated with Climate Change May Impact Our Results of Operations and Cash Flows
Physical risks of climate change, such as more frequent or more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, and other related phenomena, could affect some, or all, of our operations. Severe weather or other natural disasters could be destructive, which could result in increased costs, including supply chain costs. An extreme weather event within the Utilities' service areas can also directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment. Finally, climate change could affect the availability of a secure and economical supply of water in some locations, which is essential for continued operation of generating plants.
Future Changes in Financial Accounting Standards May Affect Our Reported Financial Results

The SEC, FASB or other authoritative bodies or governmental entities may issue new pronouncements or new interpretations of existing accounting standards that may require us to change our accounting policies. These changes are beyond our control, can be difficult to predict and could materially impact how we report our financial condition and results of operations. We could be required to apply a new or revised standard retroactively, which could adversely affect our financial position. The SEC has issuedannounced a roadmap forwork plan to aid in its evaluation of the transitionimpact that the use of IFRS by U.S. public companies would have on the U.S. securities market and has identified several potential options to incorporate IFRS in the use of IFRS promulgated by the International Accounting Standards Board. Under the SEC’s proposed roadmap, we could be required in 2014 to prepare financial statements in accordance with IFRS.United States. The SEC expects to makeannounce a determinationmore specific course of action in 2011 regarding the mandatory adoption of IFRS.2012. We are currently assessing the impact that this potential change would have on our consolidated financial statements and we will continue to monitor the development of the potential implementation of IFRS.

Increases in Taxes and Fees.

Fees May Adversely Effect Our Results of Operation, Financial Audit and Cash Flow
Due to the revenue needs of the United States and the states and jurisdictions in which we operate, various tax and fee increases may be proposed or considered. We cannot predict whether legislation or regulation will be introduced, the form of any legislation or regulation, whether any such legislation or regulation will be passed by the state legislatures or regulatory bodies. If enacted, these changes could increase tax costs and could have a negative impact on our results of operations, financial condition and cash flows.

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Risks Associated With Financing and Capital Structure
Disruptions in the Capital and Credit Markets May Adversely Affect Our Business, Including the Availability and Cost of Short-Term Funds for Liquidity Requirements, Our Ability to Meet Long-Term Commitments, Our Ability to Hedge Effectively Our Generation Portfolio, and the Competitiveness and Liquidity of Energy Markets; Each Could Adversely Affect Our Results of Operations, Cash Flows and Financial Condition
We rely on the capital markets to meet our financial commitments and short-term liquidity needs if internal funds are not available from our operations. We also use letters of credit provided by various financial institutions to support our hedging operations. Disruptions in the capital and credit markets could adversely affect our ability to draw on our respective credit facilities. Our access to funds under those credit facilities is dependent on the ability of the financial institutions that are parties to the facilities to meet their funding commitments. Those institutions may not be able to meet their funding commitments if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests within a short period of time.
Longer-term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant financial institutions could adversely affect our access to liquidity needed for our business. Any disruption could require us to take measures to conserve cash until the markets stabilize or until alternative credit arrangements or other funding for our business needs can be arranged. Such measures could include deferring capital expenditures, changing hedging strategies to reduce collateral-posting requirements, and reducing or eliminating future dividend payments or other discretionary uses of cash.
The strength and depth of competition in energy markets depends heavily on active participation by multiple counterparties, which


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could be adversely affected by disruptions in the capital and credit markets. Reduced capital and liquidity and failures of significant institutions that participate in the energy markets could diminish the liquidity and competitiveness of energy markets that are important to our business. Perceived weaknesses in the competitive strength of the energy markets could lead to pressures for greater regulation of those markets or attempts to replace those market structures with other mechanisms for the sale of power, including the requirement of long-term contracts, which could have a material adverse effect on our results of operations and cash flows.
Interest Rates and/or a Credit Rating Downgrade Could Negatively Affect Our Financing Costs, Our Ability to Access Capital and Our Requirement to Post Collateral
We have near-term exposure to interest rates from outstanding indebtedness indexed to variable interest rates, and we have exposure to future interest rates to the extent we seek to raise debt in the capital markets to meet maturing debt obligations and fund construction or other investment opportunities. The recentPast disruptions in capital and credit markets have resulted in higher interest rates on new publicly issued debt securities, increased costs for certain of our variable interest rate debt securities and failed remarketings (all of which were eventually remarketed) of variable interest rate tax-exempt debt issued to finance certain of our facilities. Continuation of theseSimilar future disruptions could increase our financing costs and adversely affect our results of operations. Also, interest rates could change as a result of economic or other events that our risk management processes were not established to address. As a result, we cannot always predict the impact that our risk management decisions may have on us if actual events lead to greater losses or costs than our risk management positions were intended to hedge. Although we employ risk management techniques to hedge against interest rate volatility, significant and sustained increases in market interest rates could materially increase our financing costs and negatively impact our reported results of operations.

We rely on access to bank and capital markets as sources of liquidity for cash requirements not satisfied by cash from operations. A downgrade in our credit ratings from the nationally recognized credit rating agencies, particularly to a level below investment grade, could negatively affect our ability to access the bank and capital markets, especially in a time of uncertainty in either of those markets, and may require us to post cash collateral to support outstanding commodity positions in the wholesale market, as well as available letters of credit and other guarantees. Furthermore, a downgrade could increase the cost of such capital by causing us to incur higher interest rates and fees associated with such capital. A rating downgrade would also increase the fees we pay on our various existing credit facilities, thus increasing the cost of our working capital. A rating downgrade could also impact our ability to grow our businesses by substantially increasing the cost of, or limiting access to, capital. 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. As a result, FirstEnergy may be required to post up to $48 million of collateral. Moody's and Fitch affirmed the ratings and stable outlook of FirstEnergy and its subsidiaries on February 11, 2010.

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

Our credit ratings also govern the collateral provisions of certain contract guarantees. Subsequent to the occurrence of a credit rating downgrade to below investment grade or a “material adverse event,” the immediate posting of cash collateral may be required. See Note 15(B)16, Commitments, Guarantees and Contingencies - Guarantees and Other Assurances of the Combined Notes to the Consolidated Financial Statements for more information associated with a credit ratings downgrade leading to the posting of cash collateral.

We Must Rely on Cash from Our Subsidiaries and Any Restrictions on Our Utility Subsidiaries’ Ability to Pay Dividends or Make Cash Payments to Us May Adversely Affect Our Financial Condition

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

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

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

40
Disruptions in the Capital and Credit Markets May Adversely Affect our Business, Including the Availability and Cost of Short-Term Funds for Liquidity Requirements, Our Ability to Meet Long-Term Commitments, our Ability to Hedge Effectively our Generation Portfolio, and the Competitiveness and Liquidity of Energy Markets; Each Could Adversely Affect our Results of Operations, Cash Flows and Financial Condition

We rely on the capital markets to meet our financial commitments and short-term liquidity needs if internal funds are not available from our operations. We also use letters of credit provided by various financial institutions to support our hedging operations. Disruptions in the capital and credit markets, as have been experienced during 2008, could adversely affect our ability to draw on our respective credit facilities. Our access to funds under those credit facilities is dependent on the ability of the financial institutions that are parties to the facilities to meet their funding commitments. Those institutions may not be able to meet their funding commitments if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests within a short period of time.

Longer-term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant financial institutions could adversely affect our access to liquidity needed for our business. Any disruption could require us to take measures to conserve cash until the markets stabilize or until alternative credit arrangements or other funding for our business needs can be arranged. Such measures could include deferring capital expenditures, changing hedging strategies to reduce collateral-posting requirements, and reducing or eliminating future dividend payments or other discretionary uses of cash.

The strength and depth of competition in energy markets depends heavily on active participation by multiple counterparties, which could be adversely affected by disruptions in the capital and credit markets. Reduced capital and liquidity and failures of significant institutions that participate in the energy markets could diminish the liquidity and competitiveness of energy markets that are important to our business. Perceived weaknesses in the competitive strength of the energy markets could lead to pressures for greater regulation of those markets or attempts to replace those market structures with other mechanisms for the sale of power, including the requirement of long-term contracts, which could have a material adverse effect on our results of operations and cash flows.

Questions Regarding the Soundness of Financial Institutions or Counterparties Could Adversely Affect Us

We have exposure to many different domestic and foreign financial institutions and counterparties and we routinely execute transactions with counterparties in connection with our hedging activities, including brokers and dealers, commercial banks, investment banks and other institutions and industry participants. Many of these transactions expose us to credit risk in the event that any of our lenders or counterparties are unable to honor their commitments or otherwise default under a financing agreement. We also deposit cash balances in short-term investments. Our ability to access our cash quickly depends on the soundness of the financial institutions in which those funds reside. Any delay in our ability to access those funds, even for a short period of time, could have a material adverse effect on our results of operations and financial condition.

We Must Rely on Cash from Our Subsidiaries and Any Restrictions on Our Utility Subsidiaries' Ability to Pay Dividends or Make Cash Payments to Us May Adversely Affect Our Financial Condition
ITEM 1B. UNRESOLVED STAFF COMMENTSWe are a holding company and our investments in our subsidiaries are our primary assets. Substantially all of our business is conducted by our subsidiaries. Consequently, our cash flow is dependent on the operating cash flows of our subsidiaries and their ability to upstream cash to the holding company. Our utility subsidiaries are regulated by various state utility commissions that generally possess broad powers to ensure that the needs of utility customers are being met. Those state commissions could attempt to impose restrictions on the ability of our utility subsidiaries to pay dividends or otherwise restrict cash payments to us.
We Cannot Assure Common Shareholders that Future Dividend Payments Will be Made, or if Made, in What Amounts they May be Paid

Our Board of Directors regularly evaluates our common stock dividend policy and determines the dividend rate each quarter. The level of dividends will continue to be influenced by many factors, including, among other things, our earnings, financial condition and cash flows from subsidiaries, as well as general economic and competitive conditions. We cannot assure common shareholders that dividends will be paid in the future, or that, if paid, dividends will be at the same amount or with the same frequency as in the past.
ITEM 1B.UNRESOLVED STAFF COMMENTS
None.


ITEM 2.   PROPERTIES39


ITEM 2.PROPERTIES
The Utilities’ (other than ATSIOhio Companies', Penn's, FGCO’s and JCP&L) and FGCO’sNGC’s respective first mortgage indentures constitute in the opinion of their counsel, direct first liens on substantially all of the respective Utilities’, FGCO’s and NGC's physical property, subject only to excepted encumbrances, as defined in the first mortgage indentures. See Notes 6, Leases, and 12, Capitalization of the “Leases” and “Capitalization” notesCombined Notes to the respective financial statementsConsolidated Financial Statements for information concerning leases and financing encumbrances affecting certain of the Utilities’, FGCO’s and NGC'sNGC’s properties.

FirstEnergy has access, either through ownership or lease, tocontrols the following generation sources as of January 31, 2010,2012, shown in the table below. Except for the leasehold interests, and OVEC participation and wind power arrangements referenced in the footnotes to the table, substantially all of theFES' competitive generating units are owned by NGC (nuclear) and FGCO (non-nuclear).; the regulated generating units are owned by JCP&L and MP.


40


      Competitive  
Plant (Location) Unit Total FES AE Supply Regulated
    Net Demonstrated Capacity (MW)
Super-critical Coal-fired:  
        
Bruce Mansfield (Shippingport, PA) 1
 830
(1) 
830
 —
 —
Bruce Mansfield (Shippingport, PA) 2
 830
(2) 
830
 —
 —
Bruce Mansfield (Shippingport, PA) 3
 830
(3) 
830
 —
 —
Harrison (Haywood, WV) 1-3
 1,984
 —
 1,576
 408
Hatfield's Ferry (Masontown, PA) 1-3
 1,710
 —
 1,710
 —
Pleasants (Willow Island, WV) 1-2
 1,300
 —
 1,200
 100
W. H. Sammis (Stratton, OH) 6-7
 1,200
  
1,200
 —
 —
Fort Martin (Maidsville, WV) 1-2
 1,107
 —
 —
 1,107
Eastlake (Eastlake, OH)(4)
 5
 597
 597
 —
 —
    10,388
 4,287
 4,486
 1,615
Sub-critical and Other Coal-fired:          
W. H. Sammis (Stratton, OH) 1-5
 1,020
  
1,020
 —
 —
Eastlake (Eastlake, OH)(4)
 1-4
 636
 636
 —
 —
Bay Shore (Toledo, OH) 1
 136
 136
    
Bay Shore (Toledo, OH)(4)
 2-4
 495
 495
 —
 —
Armstrong (Adrian, PA)(4)
 1-2
 356
 —
 356
 —
Albright (Albright, WV)(4)
 1-3
 292
 —
 —
 292
Mitchell (Courtney, PA) 3
 288
 —
 288
 —
Lakeshore (Cleveland, OH)(4)
 18
 245
 245
 —
 —
Ashtabula (Ashtabula, OH)(4)
 5
 244
 244
 —
 —
Willow Island (Willow Island, WV)(4)
 1-2
 242
 —
 —
 242
Rivesville (Rivesville, WV)(4)
 5-6
 126
 —
 —
 126
R. Paul Smith (Williamsport, MD)(4)
 3-4
 116
 —
 116
 —
R. E. Burger (Shadyside, OH) 3
 94
 94
 —
 —
OVEC (Cheshire, OH) (Madison, IN) 1-11
 188
(5) 
110
 67
 11
   
 4,478
  
2,980
 827
 671
Nuclear:  
  
  
     
Beaver Valley (Shippingport, PA) 1
 911
  
911
 —
 —
Beaver Valley (Shippingport, PA) 2
 904
(6) 
904
 —
 —
Davis-Besse (Oak Harbor, OH) 1
 908
  
908
 —
 —
Perry (N. Perry Village, OH) 1
 1,268
(7) 
1,268
 —
 —
   
 3,991
  
3,991
 —
 —
Gas/Oil-fired:  
  
  
     
AE Nos. 1, 2, 3, 4 & 5 (Springdale, PA) 1-5
 638
 —
 638
 —
West Lorain (Lorain, OH) 1-6
 545
  
—
 545
 —
AE Nos. 12 & 13 (Chambersburg, PA) 12-13
 88
 —
 88
 —
AE Nos. 8 & 9 (Gans, PA) 8-9
 88
 —
 88
 —
Mitchell (Courtney, PA) 2
 82
 —
 82
 —
Hunlock CT (Hunlock Creek, PA) 1
 45
 —
 45
 —
Buchanan (Oakwood, VA) 1-2
 43
(8) 
—
 43
 —
Other   216
 216
 —
 —
    1,745
 216
 1,529
 —
Pumped-storage and Hydro:  
  
  
     
Bath County (Warm Springs, VA) 1-6
 1,110
(9) 
—
 660
 450
Seneca (Warren, PA) 1-3
 451
  
451
 —
 —
Yard’s Creek (Blairstown Twp., NJ) 1-3
 200
(10) 
—
 —
 200
Lake Lynn (Lake Lynn, PA) 1-4
 52
(11) 
—
 52
  
Other   19
 —
 19
 —
    1,832
 451
 731
 650
Wind Power  
 376
(12) 
376
 —
 —
Total   22,810
 12,301
 7,573
 2,936

41
     Net 
     Demonstrated 
     Capacity 
  
Unit
  
(MW)
 
Plant-Location      
Coal-Fired Units      
Ashtabula-      
Ashtabula, OH  5   244 
Bay Shore-        
Toledo, OH  1-4   631 
R. E. Burger-        
Shadyside, OH  3-5   406 
Eastlake-Eastlake, OH  1-5   1,233 
Lakeshore-        
Cleveland, OH  18   245 
Bruce Mansfield-  1   830(a)
Shippingport, PA  2   830(b)
   3   830(c)
W. H. Sammis - Stratton, OH  1-7   2,220 
Kyger Creek - Cheshire, OH  1-5   118(d)
Clifty Creek - Madison, IN  1-6   142(d)
Total      7,729 
         
Nuclear Units        
Beaver Valley-  1   911 
Shippingport, PA  2   904(e)
Davis-Besse-        
Oak Harbor, OH  1   908 
Perry-        
N. Perry Village, OH  1   1,268(f)
Total      3,991 
         
Oil/Gas - Fired/        
Pumped Storage Units        
Richland - Defiance, OH  1-6   432 
Seneca - Warren, PA  1-3   451 
Sumpter - Sumpter Twp, MI  1-4   340 
West Lorain - Lorain, OH  1-6   545 
Yard’s Creek - Blairstown        
Twp., NJ  1-3   200(g)
Other      282 
Total      2,250 
Total      13,970 

41


Notes:(a)
(1)
Includes FGCO’s leasehold interest of 93.825% (779 MW) and CEI’s leasehold interest of 6.175% (51 MW), which has been assigned to FGCO.
(b)
(2)
Includes CEI’s and TE’s leasehold interests of 27.17% (226 MW) and 16.435% (136 MW), respectively, which have been assigned to FGCO.
(c)
(3)
Includes CEI’s and TE’s leasehold interests of 23.247% (193 MW) and 18.915% (157 MW), respectively, which have been assigned to FGCO.
(d)
(4)
During the first quarter of 2012, FirstEnergy announced that these coal-fired plants will be retired by September 1, 2012, subject to review for reliability impacts by PJM.
(5)
Represents FGCO’s 11.5%4.85% and AE's 3.5% entitlement based on itstheir participation in OVEC.
(e)
(6)
Includes OE’s leasehold interest of 16.65% (151 MW) from non-affiliates.
(f)
(7)
Includes OE’s leasehold interest of 8.11% (103 MW) from non-affiliates.
(g)
(8)
Buchanan Energy is a subsidiary of AE Supply. CNX Gas Corporation and Buchanan Energy have equal ownership interests in Buchanan Generation, LLC. AE Supply operates and dispatches 100% of Buchanan Generation, LLC's 86 MWs.
(9)
Represents capacity entitlement through ownership of AGC.
(10)
Represents JCP&L’s 50% ownership interest.
(11)
AE Supply has a license for Lake Lynn through 2024.
(12)
Includes 167 MW from leased facilities and 209 MW under power purchase agreements.

The above generating plants and load centers are connected by a transmission system consisting of elements having various voltage ratings ranging from 23 kV to 500 kV. The Utilities’ overhead and underground transmission lines aggregate 15,06524,305 pole miles.

The Utilities’ electric distribution systems include 119,024254,899 miles of overhead pole line and underground conduit carrying primary, secondary and street lighting circuits. They own substations with a total installed transformer capacity of 91,048,000approximately 140,158,000 kV-amperes.

.

42
TheAll of FirstEnergy's generation, transmission facilities that are owned by ATSI are currently operated on an integrated basis as part of MISO and are interconnected with facilities operated bydistribution assets operate in PJM. In December 2009, however, the FERC approved ATSI’s realignment into PJM, subject to certain conditions. The transmission facilities of JCP&L, Met-Ed and Penelec are physically interconnected and are operated on an integrated basis as part of PJM
FirstEnergy’s distribution and transmission systems as of December 31, 2009,2011, consist of the following:

       Substation 
 
Distribution
  Transmission  Transformer 
 
Lines
  
Lines
  
Capacity
 
 (Miles)  (kV-amperes) 
Distribution
Lines(1)
 
Transmission
Lines(1)
 
Substation
Transformer
Capacity(2)
           kV Amperes
OE  30,465   550   9,503,000 62,238
 461
 7,763,000
Penn  5,945   44   1,057,000 13,419
 52
 1,425,000
CEI  25,366   2,144   7,830,000 33,252
 —
 8,938,000
TE  2,122   223   2,973,000 17,593
 81
 3,040,000
JCP&L  19,775   2,160   21,967,000 22,800
 2,550
 23,150,000
Met-Ed  15,128   1,422   10,353,000 18,695
 1,406
 10,819,000
Penelec  20,223   2,701   13,978,000 27,131
 2,909
 15,234,000
ATSI*  -   5,821   23,387,000 
ATSI(3)
—
 7,524
 23,578,000
WP20,026
 4,419
 14,077,000
MP20,730
 2,625
 15,230,000
PE19,015
 2,126
 11,033,000
TrAIL(4)
—
 152
 5,871,000
Total  119,024   15,065   91,048,000 254,899
 24,305
 140,158,000

*
(1)
Pole miles
(2)
Top rating of in-service power transformers only. Excludes grounding banks, station power transformers, and generator and customer-owned transformers.
(3)
Represents transmission lines of 69kV and above located in the service areas of OE, Penn, CEI and TE.
(4)
Represents transmission lines at 500kV located in the service areas of MP, PE and WP.
ITEM 3.LEGAL PROCEEDINGS
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 reduction 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 approved by the PUCO. The named-defendant companies intend to assert all applicable defenses, including the lack of jurisdiction of the court of common pleas, and to challenge any class certification.
Reference is made to Note 15,16, Commitments, Guarantees and Contingencies of FirstEnergy’sthe Combined Notes to the Consolidated Financial Statements contained in Item 8 for a description of certain legal proceedings involving FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec.

ITEM 4.SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERSMINE SAFETY DISCLOSURE
Signal Peak Mine Safety
During 2011, FirstEnergy, through its FEV wholly owned subsidiary, held a 50% interest in Global Mining Group, LLC, a joint venture owning Signal Peak, which is a company that constructed and operates the Bull Mountain Mine No. 1 (Mine), an underground coal mine near Roundup Montana. The operation of the Mine is subject to regulation by the MSHA under the Mine Act.


None.42


On October 18, 2011, FirstEnergy announced that Gunvor Group, Ltd. signed an agreement to purchase a one-third interest in the Signal Peak coal mine in Montana. As a result of the sale, FirstEnergy, through its wholly owned subsidiary, FEV, currently has a 33-1/3% interest in Global Holding, a joint venture that owns Signal Peak.
Information concerning mine safety violations or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act is included in Exhibit 95 to this Annual Report on Form 10-K.
PART II

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

The information required by Item 5 regarding FirstEnergy’s market information, including stock exchange listings and quarterly stock market prices, dividends and holders of common stock is included on page 1 of FirstEnergy’s 2009 Annual Report to Stockholders (Exhibit 13.1). Pursuant to General Instruction I of Form 10-K, informationin Item 6.
Information for FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec is not required to be disclosed because they are wholly owned subsidiaries.

subsidiaries of FirstEnergy and there is no market for their common stock.
Information regarding compensation plans for which shares of FirstEnergy common stock may be issued is incorporated herein by reference to FirstEnergy’s 20102012 proxy statement to be filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.

43
The table below includes information on a monthly basis regarding purchases made by FirstEnergyFE of its common stock during the fourth quarter of 2009.2011.

 Period 
 
October
  
November
  
December
  
Fourth Quarter
 
Total Number of Shares Purchased(a)
  15,928   29,860   388,426   434,214 
 Period
 October November December Fourth Quarter
Total Number of Shares Purchased(1)
 112,225
 167,674
 712,539
 992,438
Average Price Paid per Share $45.84  $42.99  $43.28  $43.36  $44.36
 $44.32
 $44.19
 $44.23
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs  -   -   -   - 
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)
(1)
Share amounts reflect purchases on the open market to satisfy FirstEnergy's obligations to deliver common stock under itsfor some or all of the following: 2007 Incentive Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan, Director Compensation, Allegheny Energy, Inc. 1998 Long-Term Incentive Plan, Allegheny Energy, Inc. 2008 Long-Term Incentive Plan, Allegheny Energy, Inc, Non-Employee Director Stock Plan, Allegheny Energy, Inc, Amended and Restated Revised Plan for Deferral of Compensation of Directors, and Stock Investment Plan. In addition, such amounts reflect shares tendered by employees to pay the exercise price or withholding taxes under the 2007 Incentive Plan and the Executive Deferred Compensation Plan, and any shares that may have been purchased as part of publicly announced plans.
ITEM 6.SELECTED FINANCIAL DATA
For the Years Ended December 31, 2011 
2010(1)
 
2009(1)
 
2008(1)
 
2007(1)
  (In millions, except per share amounts)
Revenues $16,258
 $13,339
 $12,973
 $13,627
 $12,802
Earnings Available to FirstEnergy Corp.(2)
 $885
 $742
 $872
 $623
 $1,489
Earnings per Share of Common Stock:(2)
          
Basic $2.22
 $2.44
 $2.87
 $2.05
 $4.86
Diluted $2.21
 $2.42
 $2.85
 $2.03
 $4.80
Weighted Average Shares Outstanding:          
Basic 399
 304
 304
 304
 306
Diluted 401
 305
 306
 307
 310
Dividends Declared per Share of Common Stock(3)
 $2.20
 $2.20
 $2.20
 $2.20
 $2.05
Total Assets(4)
 $47,326
 $35,531
 $35,054
 $34,206
 $32,394
Capitalization as of December 31:          
Total Equity(5)
 $13,299
 $8,952
 $9,014
 $8,748
 $9,129
Long-Term Debt and Other Long-Term Obligations 15,716
 12,579
 12,008
 9,100
 8,869
Total Capitalization(5)
 $29,015
 $21,531
 $21,022
 $17,848
 $17,998
(1)
Reflects the retrospective change in recognizing pensions and OPEB costs.
(2)
The retrospective change in accounting for pensions and OPEB costs decreased Earnings Available to FirstEnergy Corp and Earnings Per Share (basic; diluted) as follows: 2010 - $42 million ($0.14; $0.15 per share), 2009 - $134 million ($0.44; $0.44 per share) and 2008 - $719


FIRSTENERGY CORP.43


SELECTED FINANCIAL DATAmillion ($2.36; $2.35 per share); and increased Earnings Available to FirstEnergy Corp. and Earnings Per Share (basic; diluted) in 2007 by $180 million ($0.59; $0.58 per share).

For the Years Ended December 31, 2009  2008  2007  2006  2005 
  (In millions, except per share amounts)    
                
Revenues $12,967  $13,627  $12,802  $11,501  $11,358 
Income From Continuing Operations $1,006  $1,342  $1,309  $1,258  $879 
Earnings Available to FirstEnergy Corp. $1,006  $1,342  $1,309  $1,254  $861 
Basic Earnings per Share of Common Stock:                    
Income from continuing operations $3.31  $4.41  $4.27  $3.85  $2.68 
Earnings per basic share $3.31  $4.41  $4.27  $3.84  $2.62 
Diluted Earnings per Share of Common Stock:                    
Income from continuing operations $3.29  $4.38  $4.22  $3.82  $2.67 
Earnings per diluted share $3.29  $4.38  $4.22  $3.81  $2.61 
Dividends Declared per Share of Common Stock (1)
 $2.20  $2.20  $2.05  $1.85  $1.705 
Total Assets $34,304  $33,521  $32,311  $31,196  $31,841 
Capitalization as of December 31:                    
Total Equity $8,557  $8,315  $9,007  $9,069  $9,225 
Preferred Stock  -   -   -   -   184 
Long-Term Debt and Other Long-Term                    
Obligations  11,908   9,100   8,869   8,535   8,155 
Total Capitalization $20,465  $17,415  $17,876  $17,604  $17,564 
                     
Weighted  Average Number of Basic                    
Shares Outstanding  304   304   306   324   328 
                     
Weighted  Average Number of Diluted                    
Shares Outstanding  306   307   310   327   330 

(1)
(3)
Dividends declared in 2011, 2010, 2009 and 2008 include four quarterly dividends of $0.55 per share. Dividends declared in 2007 include three quarterly payments of $0.50 per share in 2007 and one quarterly payment of $0.55 per share in 2008.  Dividends declared
(4)
The retrospective change in 2006 include three quarterly paymentsaccounting for pensions and OPEB costs increased Total Assets as of $0.45 per shareDecember 31 as follows: 2010 - $726 million, 2009 - $750 million, 2008 - $685 million and 2007 - $83 million.
(5)
The retrospective change in 2006accounting for pensions and one quarterly paymentOPEB costs increased Total Equity as of $0.50  per share in 2007. Dividends declared in 2005 include two quarterly payments of $0.4125 per share in 2005, one quarterly payment of $0.43  per share in 2005December 31 as follows: 2010 - $439 million, 2009 - $457 million, 2008 - $433 million and one quarterly payment of $0.45 per share in 2006 Dividends declared in 2004 include four quarterly dividends of $0.375  per share paid in 2004 and a quarterly dividend of $0.4125 per share paid in 2005.2007 - $122 million.

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PRICE RANGE OF COMMON STOCK

The common stock of FirstEnergy Corp. is listed on the New York Stock Exchange under the symbol "FE"“FE” and is traded on other registered exchanges.

  2009  2008 
First Quarter High-Low
 $53.63  $35.63  $78.51  $64.44 
Second Quarter High-Low
 $43.29  $35.26  $83.49  $69.20 
Third Quarter High-Low
 $47.82  $36.73  $84.00  $63.03 
Fourth Quarter High-Low
 $47.77  $41.57  $66.69  $41.20 
Yearly High-Low
 $53.63  $35.26  $84.00  $41.20 
                 
Prices are from http://finance.yahoo.com.
 
 2011 2010
 High Low High Low
First Quarter$40.80
 $36.11
 $47.09
 $38.31
Second Quarter$45.80
 $36.50
 $39.96
 $33.57
Third Quarter$46.51
 $38.77
 $39.06
 $34.51
Fourth Quarter$46.10
 $41.55
 $40.12
 $35.00
Yearly$46.51
 $36.11
 $47.09
 $33.57
Prices are from http://finance.yahoo.com.
SHAREHOLDER RETURN

The following graph shows the total cumulative return from a $100 investment on December 31, 20042006 in FirstEnergy’s common stock compared with the total cumulative returns of EEI’s Index of Investor-Owned Electric Utility Companies and the S&P 500.



HOLDERS OF COMMON STOCK

There were 110,712115,120 and 110,365114,808 holders of 304,835,407418,216,437 shares of FirstEnergy'sFirstEnergy’s common stock as of December 31, 20092011 and January 31, 2010,2012, respectively. Information regarding retained earnings available for payment of cash dividends is given in Note 12, Capitalization of the Combined Notes to the consolidated financial statements.Consolidated Financial Statements.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.


ITEM 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT AND SUBSIDIARIES44


ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT AND SUBSIDIARIES

Forward-Looking Statements: This Form 10-K 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’smanagement'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.


45
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 regulatory process on the pending matters in Ohio, 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 or to recover increased transmission costs.
·Operation and maintenance costs being higher than anticipated.
·Other legislative and regulatory changes, and revised environmental requirements, including possible GHG emission regulations.
·The potential impacts of the U.S. Court of Appeals’ July 11, 2008 decision requiring revisions to the CAIR rules and the scope of any laws, rules or regulations that may ultimately take their place.
·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 TSC 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 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 decline of the national and regional economy and its impact on the registrants’ major industrial and commercial customers.
·Issues concerning the soundness of financial institutions and counterparties with which the registrants do business.
·The 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 our 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 speed and nature of increased competition in the electric utility industry.
The impact of the regulatory process on the pending matters before FERC in the various states in which we do business including, but not limited to, matters related to rates.
The status of the PATH project in light of PJM's direction to suspend work on the project pending review of its planning process, its re-evaluation of the need for the project and the uncertainty of the timing and amounts of any related capital expenditures.
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.
Financial derivative reforms that could increase our liquidity needs and collateral costs.
The continued ability of FirstEnergy's regulated utilities to collect transition and other costs.
Operation and maintenance costs being higher than anticipated.
Other legislative and regulatory changes, and revised environmental requirements, including possible GHG emission, water intake and coal combustion residual regulations, the potential impacts of any laws, rules or regulations that ultimately replace CAIR, including CSAPR which was stayed by the courts on December 30, 2011, and the effects of the EPA's MATS rules.
The uncertainty of the timing and amounts of the capital expenditures that may arise in connection with litigation, including NSR litigation or potential regulatory initiatives or rulemakings (including that such expenditures could result in our decision to shut down or idle certain generating units).
The uncertainty associated with the company's plan to retire its older unscrubbed regulated and competitive fossil units, including the impact on vendor commitments and PJM's review of the company's plans.
Adverse regulatory or legal decisions and outcomes with respect to our nuclear operations (including, but not limited to the revocation or non-renewal of necessary licenses, approvals or operating permits by the NRC including as a result of the incident at Japan's Fukushima Daiichi Nuclear Plant).
Issues that could result from our continuing investigation and analysis of the indications of cracking in the plant shield building at Davis-Besse.
Adverse legal decisions and outcomes related to Met-Ed's and Penelec's ability to recover certain transmission costs through their transmission service charge riders.
The continuing availability of generating units and changes in their ability to operate at or near full capacity.
Replacement power costs being higher than anticipated or inadequately hedged.
The ability to comply with applicable state and federal reliability standards and energy efficiency mandates.
Changes in customers' demand for power, including but not limited to, changes resulting from the implementation of state and federal energy efficiency mandates.
The ability to accomplish or realize anticipated benefits from strategic goals.
FirstEnergy's ability to improve electric commodity margins and the impact of, among other factors, the increased cost of coal and coal transportation on such margins.
The ability to experience growth in the distribution business.
The changing market conditions that could affect the value of assets held in FirstEnergy's NDTs, pension trusts and other trust funds, and cause FirstEnergy and its subsidiaries to make additional contributions sooner, or in amounts that are larger than currently anticipated.
The impact of changes to material accounting policies.
The ability to access the public securities and other capital and credit markets in accordance with FirstEnergy's financing plan, the cost of such capital and overall condition of the capital and credit markets affecting FirstEnergy and its subsidiaries.
Changes in general economic conditions affecting FirstEnergy and its subsidiaries.
Interest rates and any actions taken by credit rating agencies that could negatively affect FirstEnergy's and its subsidiaries' access to financing or their costs of financings and increase requirements to post additional collateral to support outstanding commodity positions, LOCs and other financial guarantees.
The continuing uncertainty of the national and regional economy and its impact on major industrial and commercial customers of FirstEnergy and its subsidiaries.
Issues concerning the soundness of financial institutions and counterparties with which FirstEnergy and its subsidiaries do business.
Issues arising from the completed merger of FirstEnergy and AE and the ongoing coordination of their combined operations


45


including FirstEnergy's ability to maintain relationships with customers, employees or suppliers, as well as the ability to continue to successfully integrate the businesses and realize cost savings and any other synergies .
The risks and other factors discussed from time to time in FirstEnergy's and its applicable subsidiaries' SEC filings, and other similar factors.

Dividends declared from time to time on FE's common stock during any annual period may in the aggregate vary from the indicated amount due to circumstances considered by FE's Board of Directors at the time of the actual declarations. A security rating is not a recommendation to buy or hold securities and is subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.
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’FirstEnergy's 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, except as required by law, any forward-looking statements contained herein as a result of new information, future events or otherwise.
See Item 1A. Risk Factors for additional information regarding risks that may impact our business, financial condition and results of operations.


46
46


FIRSTENERGY CORP.

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


OVERVIEW
EXECUTIVE SUMMARY

Earnings available to FirstEnergy Corp. in 20092011 were $1.01 billion,$885 million, or $2.22 per basic earnings of $3.31 per share of common stock ($3.29($2.21 diluted), compared with earnings available to FirstEnergy Corp. of $1.34 billion,$742 million, or $2.44 per basic earnings of $4.41 per share of common stock ($4.38($2.42 diluted), in 20082010 and $1.31 billion,$872 million, or $2.87 per basic earnings of $4.27 per share ($4.22($2.85 diluted), in 2007.2009.
Change in Earnings Per Basic Share From Prior Year 2011 2010
     
Earnings Per Basic Share — Prior Year $2.44
 $2.87
Segment operating results(1)-
    
Regulated Distribution 0.05
 0.04
Competitive Energy Services (0.15) 0.10
Regulated Independent Transmission (0.06) 0.12
Non-core asset sales/impairments 0.67
 (0.37)
Generating plant impairments 0.08
 (0.78)
Trust securities impairments 0.02
 0.03
Litigation resolution (0.07) 0.01
Regulatory charges 0.03
 0.45
Mark-to-market adjustments-    
Pension and OPEB actuarial assumptions (0.47) 0.30
All other 0.02
 0.35
Organizational restructuring - 2009 —
 0.14
Debt redemption premiums (0.01) 0.32
Merger-related costs (0.29) (0.16)
Merger Accounting - commodity contracts (0.26) —
Net merger accretion(1)(2)(3)
 0.54
 —
Income tax resolution / retiree drug subsidy (0.03) (0.57)
Settlement of uncertain tax positions (0.05) (0.11)
Depreciation (0.09) (0.02)
Interest expense, net of amounts capitalized (0.14) 0.04
Investment income (0.03) (0.19)
Change in effective tax rate 0.04
 (0.17)
Other (0.02) 0.04
Earnings Per Basic Share $2.22
 $2.44
(1)Excludes amounts that are shown separately
(2)Includes dilutive effect of shares issued in connection with the Allegheny merger
(3)Includes 10 months of Allegheny results in 2011

Change in Basic Earnings Per Share From Prior Year 2009  2008 
Basic Earnings Per Share – Prior Year $4.41  $4.27 
Non-core asset sales/impairments  0.47   0.02 
Litigation settlement  (0.03)  0.03 
Trust securities impairment  0.16   (0.20)
Saxton decommissioning regulatory asset – 2007  -   (0.05)
Regulatory charges  (0.55)  - 
Derivative mark-to-market adjustment  (0.42)  - 
Organizational restructuring  (0.14)  - 
Debt redemption premiums  (0.31)  - 
Income tax resolution  0.68   - 
Revenues  (1.85)  1.61 
Fuel and purchased power  (0.09)  (1.24)
Amortization of regulatory assets, net  (0.02)  (0.44)
Investment income  0.20   0.08 
Interest expense  (0.14)  0.04 
Reduced common shares outstanding  -   0.03 
Transmission expenses  0.73   (0.02)
Other expenses  0.21   0.28 
Basic Earnings Per Share $3.31  $4.41 

Financial Matters

Proposed Merger with Allegheny Energy, Inc.

On February 10, 2010, we entered into a Merger Agreement with Allegheny25, 2011, the consummation of which will result, among other things, in our becoming an electric utility holding company for:

·generation subsidiaries owning or controlling approximately 24,000 MWs of generating capacity from a diversified mix of regional coal, nuclear, natural gas, oil and renewable power,
·ten regulated electric distribution subsidiaries providing electric servicemerger between FirstEnergy and AE closed. Pursuant to more than six million customers in Pennsylvania, Ohio, Maryland, New Jersey, New York, Virginia and West Virginia, and
·transmission subsidiaries owning over 20,000 miles of high-voltage lines connecting the Midwest and Mid-Atlantic.
Upon the terms of the Agreement and subject to the conditions set forth in thePlan of Merger Agreement,between FirstEnergy, Merger Sub will mergeand AE, Merger Sub merged with and into AlleghenyAE with AlleghenyAE continuing as the surviving corporation and a wholly-ownedwholly owned subsidiary of FirstEnergy. Pursuant to the Merger Agreement, upon the closingAs part of the merger, each issued and outstanding share of Allegheny common stock, including grants of restricted common stock, will automatically be converted into the right to receiveAE shareholders received 0.667 of a share of FirstEnergy common stock of FirstEnergy. Completionfor each AE share outstanding as of the merger is conditioned upon, among other things, shareholder approval of both companies as well as expiration or termination of any applicable waiting period undercompletion date and all outstanding AE equity-based employee compensation awards were converted into FirstEnergy equity-based awards on the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and approval by the FERC, the Maryland Public Service Commission, PPUC, the Virginia State Corporation Commission and the West Virginia Public Service Commission. We anticipate that the necessary approvals will be obtained within 12 to 14 months. The Merger Agreement contains certain termination rights for both us and Allegheny, and further provides for the payment of fees and expenses upon termination under specified circumstances. Further information concerning the proposed merger will be included in a joint proxy statement/prospectus contained in the registration statement on Form S-4 to be filed by us with the SEC insame basis.
In connection with the merger.merger, FirstEnergy recorded merger transaction costs of approximately $91 million ($73 million net of tax and $65 million ($47 million net of tax) during 2011 and 2010, respectively. These costs are included in “Other operating expenses” in the Consolidated Statements of Income. In addition, during 2011, $93 million of pre-tax merger integration costs and $36 million of pre-tax charges from merger settlements approved by regulatory agencies were recognized. Charges resulting from merger settlements are not expected to be material in future periods.
FirstEnergy exceeded its 2011 merger benefits target. During 2011, FirstEnergy completed savings initiatives that allowed the


47
47
Financing Activities


In 2009, we issuedcompany to capture pre-tax annualized merger benefits of approximately $3.7 billion of long-term debt (excluding PCRBs) -- $2.2 billion for our Energy Delivery Services Segment and $1.5 billion for our Competitive Energy Services Segment. The primary use of the proceeds related$267 million compared to the repaymentannual target of long-term debt of $1.9 billion and short-term borrowings of $1.2 billion (primarily from the $2.75 billion revolver), to finance capital expenditures and for other general corporate purposes, including the Utilities’ and ATSI’s voluntary contribution of $500 million to the pension plan. As a result, we extended the maturity schedule of long-term debt to an average of 14.5 years, an increase of two years from 2008. Additionally, throughout 2009, FGCO and NGC remarketed and issued $940 million of PCRBs, of which $776 million was placed in fixed rate modes.

Rating Agency Actions

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.  As a result, FirstEnergy may be required to post up to $48 million of collateral (see Note 15(B)). Moody's and Fitch affirmed the ratings and stable outlook of FirstEnergy and its subsidiaries on February 11, 2010. These rating agency actions were taken in response to the announcement of the proposed merger with Allegheny.

Previously, on June 17, 2009, Moody’s had issued a report affirming FirstEnergy’s Baa3 and FES’ Baa2 credit ratings and maintained its stable outlook and, on July 9, 2009, S&P had reaffirmed its since-lowered ratings on FirstEnergy and its subsidiaries, including a BBB corporate credit rating, and maintained its then current stable outlook.

In addition, on August 3, 2009, Moody’s 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.

Sumpter Plant Sale

On December 17, 2009, FirstEnergy announced that its FGCO subsidiary reached an agreement in principle to sell its 340 MW Sumpter Plant in Sumpter, Michigan, resulting in an impairment charge in 2009 of approximately $6 million ($4 million, after tax). The sale is expected to close in first quarter of 2010. The plant, built in 2002 by FGCO, consists of four 85-MW natural gas combustion turbines.

OVEC Participation Interest Sale

On May 1, 2009, FGCO sold a 9% interest in the output from OVEC for $252 million (214 MW from OVEC’s generating facilities in southern Indiana and Ohio). FGCO’s remaining interest in OVEC was reduced to 11.5%. This transaction increased 2009 net income by $159$210 million.

Legacy Power Contracts

During 2008, in anticipation of certain regulatory actions, FES entered into purchased power contracts representing approximately 4.4 million MWH per year for MISO delivery in 2010 and 2011. These contracts, which represented less than 10% of FES's estimated Ohio load, were intended to cover potential short positions that were anticipated in those years and qualified for the normal purchase normal sale scope exception under accounting for derivatives and hedging. In the fourth quarter of 2009, as FES determined that the short positions in 2010 and 2011 were not expected to materialize based on reductions in PLR obligations and decreased demand due to economic conditions, the contracts were modified to financially settle to avoid congestion and transmission expenses associated with physical delivery. As a result of the modification, the fair value of the contracts was recorded, resulting in a mark-to-market charge of approximately $205 million ($129 million, after tax) to purchased power expense. For all other purchased power contracts qualifying for the normal purchase normal sale scope exception, FES expects to take physical delivery of the power over the remaining term of the contracts.

Operational Matters

Recessionary Market Conditions and Weather Impacts

Customers' demand for electricity produced and sold by FirstEnergy’s competitive subsidiary, FES, along with the value of that electricity, has been impacted by conditions in competitive power markets, macro and micro economic conditions, and weather conditions in FirstEnergy’s service territories. Recessionary economic conditions, particularly in the automotive and steel industries, compounded by unusually mild regional summertime temperatures, adversely affected FirstEnergy’s operations and revenues in 2009. Generation output for 2009 was 65.9 million MWH versus 2008 output of 82.4 million MWH.

48
Customers’ demand for electricity affects FirstEnergy’s distribution, transmission and generation revenues, the quantity of electricity produced, purchased power expense and fuel expense. FirstEnergy has taken various actions and instituted a number of changes in operating practices designed to mitigate the impact of these external influences. These actions included employee severances, wage reductions, employee and retiree benefit changes, reduced levels of overtime and the use of fewer contractors. Any continuing recessionary economic conditions, coupled with unusually mild weather patterns and the resulting impact on electricity prices and demand could also adversely affect FirstEnergy's results of operations and financial condition and could require further changes in FirstEnergy’s operations.

FirstEnergy Reorganization and Voluntary Enhanced Retirement Option

Beginning March 3, 2009, FirstEnergy reduced its management and support staff by 348 employees during 2009. This staffing reduction resulted from an effort to enhance efficiencies in response to the economic downturn. The reduction represented approximately 4.5% of FirstEnergy’s non-union workforce. Total one-time charges associated with the reorganization were approximately $66 million ($41 million, after tax), or $0.14 per share of common stock.

In June 2009, FirstEnergy offered a VERO, which provided additional benefits for qualified employees who elected to retire. The VERO was accepted by 397 non-represented employees and 318 union employees.

PJM Regional Transmission Organization (RTO)RTO Integration

On August 17, 2009, FirstEnergy filed an application with the FERC to consolidate its transmission assets and operationsJune 1, 2011, ATSI successfully integrated into PJM. Currently, FirstEnergy's transmission assets and operations are divided between PJM and MISO. The consolidation would move the transmission assets that are partWith this transition, all of FirstEnergy's ATSI subsidiarygeneration, transmission and distribution facilities are located within the footprint of the Ohio Companies and Penn - intonow in PJM. On December 17, 2009, a FERC order approving the integration and outlining the terms required for the move was issued and on December 18, 2009, ATSI announced that it signed an agreement to join PJM. FirstEnergy plans to integrate its operations into PJM by June 1, 2011.

Beaver Valley Power Station License RenewalTransmission Expansion

On November 5, 2009, FENOC announced that the NRC approved a 20-year license extension for Beaver Valley Power Station Units 1May 19, 2011, TrAIL's 500-kV transmission line, spanning more than 150 miles from southwestern Pennsylvania through West Virginia to northern Virginia, was completed and 2 until 2036 and 2047, respectively. Beaver Valley is located in Shippingport, Pennsylvania and is capable of generating 1,815 MW and is the 56th out of 104 nuclear reactors in the United States to receive a license extension from the NRC.energized.

Refueling Outages

On February 23, 2009, the Perry Plant began its 12th scheduled refueling and maintenance outage, in which 280 of the plant’s 748 fuel assemblies were exchanged, safety inspections were conducted, and several maintenance projects were completed, including replacement of the plant’s recirculation pump motor. On May 13, 2009, the Perry Plant returned to service.Nuclear Generation

On April 20, 2009,11, 2011, Beaver Valley Power Station Unit 1 began its 19th scheduled2 returned to service following a March 7, 2011 shutdown for refueling and maintenance outage. During the outage, 62 of the 157 fuel assemblies were exchanged and safety inspections were conducted. Also, several projects were completed to ensure continued safe and reliable operations, including maintenance on the cooling tower and the replacement of a pump motor. On May 21, 2009, Beaver Valley Unit 1 returned to service.

On October 12, 2009, Beaver Valley Unit 2 began a scheduled refueling and maintenance outage.maintenance. During the outage, 60 of the 157 fuel assemblies were exchanged, and safety inspections were conducted. In addition,conducted, and numerous maintenance and improvement projects were completed to ensurethat we believe will result in continued safe and reliable operations. On November 27, 2009, Beaver Valley Unit 2 returned to service.
R. E. Burger Plant

On June 7, 2011, the Perry Nuclear Power Plant returned to service following a scheduled shutdown for refueling and maintenance which began on April 1, 2009, FirstEnergy announced plans to retrofit Units 4 and 5 at its R.E. Burger Plant to repower18, 2011. During the units with biomass. Retrofitting the Burger Plant is expected to help meet the renewable energy goals set forth in Ohio SB221, will utilize muchoutage, 248 of the existing infrastructure currently748 fuel assemblies were replaced and safety inspections were successfully conducted. Additionally, numerous preventative maintenance activities and improvement projects were completed that we believe will result in place, preserve approximately 100 jobscontinued safe and continue positive economic supportreliable operations, including replacement of several control rod blades, rewind of the generator, and routine work on more than 150 valves, pumps and motors.

On October 2, 2011, FENOC completed the controlled shutdown of the Perry Plant due to Belmont County, Ohio. Once complete, the Burgerloss of a startup transformer. Subsequently, a spare replacement transformer from Davis-Besse Nuclear Power Station was transported to the Perry Plant for modification and installation. The new transformer was installed in 2011.

During 2011, FENOC broke ground for new Emergency Operations Facilities at all three of its nuclear sites. Each of the 12,000 square-foot facilities will behouse activities related to maintaining public health and safety during the unlikely event of an emergency at the plant and allow for improved coordination between the plant, state and local emergency management agencies.

On October 1, 2011, the Davis-Besse Nuclear Power Station began a scheduled outage for replacement of its reactor vessel head and other scheduled maintenance. On October 10, 2011, following opening of the building for installation of the new reactor head, a sub-surface hairline crack was identified in one of the largest biomass facilitiesexterior architectural elements on the shield building. These elements serve as architectural features and do not have structural significance. During investigation of the crack at the shield building opening, concrete samples and electronic testing found similar sub-surface hairline cracks in most of the building's architectural elements. FENOC's investigation also identified other indications of cracking. Included among them were sub-surface hairline cracks in the United States.upper portion of the shield building (above 780 feet of elevation) and in the vicinity of the main steam line penetrations. A team of industry-recognized structural concrete experts and Davis-Besse engineers have determined these conditions do not affect the facility's structural integrity or safety. On February 27, 2012, FENOC sent a root cause evaluation report to the NRC. On December 6, 2011, the Davis-Besse Nuclear Power Station returned to service. The capital cost for retrofittingnew reactor vessel head features control rod nozzles made of an enhanced material and further promotes safe and reliable operation of the Burger Plant is estimated to be approximately $200 million, and once completed, is expected to be capable of producing up to 312 MW of electricity.plant.

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Fremont Energy CenterCoal and Gas Fired Generation

On September 22, 2009,July 28, 2011, FirstEnergy announced that it expects to complete constructioncompleted the sale 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 544to American Municipal Power, Inc. for $510 million based on 685 MW of load-followingoutput. The purchase price can be incrementally increased, not to exceed an additional $16 million, to reflect additional transmission export capacity up to 707 MW.

On October 18, 2011, FirstEnergy sold its Richland (432 MW) and 163Stryker (18 MW) Peaking Facilities for approximately $80 million. The proceeds from the sale of these non-core assets reduced FirstEnergy's net debt position.

On January 26, 2012, FirstEnergy announced that its unregulated generation subsidiaries will retire six older coal-fired plants located in Ohio, Pennsylvania and Maryland. On February 8, 2012, FirstEnergy announced that MP will retire three older coal-fired plants located in West Virginia. All of these generating plants will be closed by September 1, 2012. The decision to close the plants is the result of a comprehensive review of FirstEnergy's coal-fired generating facilities in light of the MATS rules that were recently finalized and other environmental regulations. These closures are subject to review for reliability impacts by PJM. In addition, MP will make a filing with the WVPSC to provide them with information regarding the retirement of its plants. As a result of this decision, impairment charges associated with these assets were recognized by FirstEnergy, aggregating approximately $334 million ($207 million after-tax) in the fourth quarter of 2011, including approximately $243 million ($152 million after-tax) which is applicable to FES. See Note 11, Impairment of Long-lived Assets, for further information on the retirement of these plants.



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The total capacity of the competitive plants that will be retired is approximately 2,700 MW and the total capacity of the three regulated plants that will be retired is approximately 660 MW. Recently, these plants served mostly as peaking capacity. Withor intermediate facilities, generating, on average, approximately 10 percent of the accelerated construction schedule,electricity produced by FirstEnergy's generation subsidiaries over the remaining cost to completepast three years.

On February 24, 2012, PJM notified FirstEnergy of its preliminary analysis of the project is estimatedreliability impacts that may result from closure of the older competitive coal-fired generating units. PJM's preliminary analysis indicated that there would be significant reliability concerns that will need to be approximately $150addressed. FirstEnergy intends to continue to actively engage in discussions with PJM regarding this notification, including the possible continued operation of certain plants.

Signal Peak

On October 18, 2011, FirstEnergy announced that Gunvor Group, Ltd. purchased a one-third interest in Global Holding, a joint venture that owns the Signal Peak coal mine in Montana and the related Global Rail coal transportation operations. The sale strengthened FirstEnergy's balance sheet in the following ways:

Proceeds of $257.5 million reduced FirstEnergy's net debt position;
De-consolidation of Signal Peak resulted in the reduction of indebtedness by $360 million and an increase to equity of $50 million on FirstEnergy's Consolidated Balance Sheet; and
The gain on sale and revaluation of FirstEnergy's remaining ownership stake increased equity by an additional $370 million.

Norton Energy Storage ProjectFollowing the sale, FirstEnergy, through its wholly owned subsidiary, FEV, has a one-third interest in Global Holding. FGCO has a long-term coal supply agreement with Signal Peak for up to 10 million tons per year. FGCO has re-evaluated its coal usage under that agreement and has determined to resell its coal purchased from Signal Peak to an affiliate of Global Holding; provided, however, that such affiliate may require FGCO to repurchase up to 2 million tons annually from the existing underground mines, and, if Signal Peak develops surface mines, it could require FGCO to purchase an additional 2 million tons per year. FirstEnergy remains a 100% guarantor on Signal Peak's and Global Rail's $350 million senior secured credit facility. See Guarantees and Other Assurances below.

FirstEnergy Utilities Respond to Unprecedented Storms

In late August 2011, FirstEnergy experienced unprecedented damage in its service territory as a result of Hurricane Irene. Approximately 1.1 million customers were affected by outages in areas served by JCP&L, Met-Ed, Penelec and PE. Approximately 5,000 FirstEnergy employees and 2,800 contractors, including utility line workers from other utilities, assisted with the restoration work. The cost of the storm totaled approximately $89 million, of which $4 million reduced pre-tax income in 2011 and $85 million was capitalized or deferred for future recovery from customers.

On November 23, 2009, FGCO announcedOctober 29, 2011, FirstEnergy was affected by a snowstorm that it purchased a 92-acre siteparalyzed much of the East Coast, including our eastern service areas. Approximately 820,000 customers of JCP&L, Met-Ed, PE, MP, Penelec and WP were affected by the storm that brought down more than 800 poles and approximately 10,000 spans of wire. More than 9,600 employees, contractors and other utilities' crews helped in Norton, Ohio,the restoration. The pre-tax total cost of the storm was approximately $125 million, of which $6 million reduced pre-tax income in 2011 and $119 million was capitalized or deferred for approximately $35 million to develop a compressed-air electric generating plant. The transaction includes rights to a 600-acre underground cavern ideal for energy storage technology. With 9.6 million cubic meters of storage, the Norton Energy Storage Project has the potential to be expanded to up to 2,700 MW of capacity. The Norton Energy Storage Project is part of FirstEnergy's overall environmental strategy, which includes continued investment in renewable and low-emitting energy resources.future recovery from customers.

Labor AgreementsFinancial Matters
During 2011, FirstEnergy redeemed or repurchased approximately $520.4 million principal amount of PCRBs, as summarized in the following table. Approximately $28.5 million of FGCO FMBs and $98.9 million of NGC FMBs associated with the PCRBs were returned for cancellation by the associated LOC providers.
SubsidiariesAmount 
 (In millions) 
AE Supply$53.0
(1) 
FGCO$198.2
(2) 
NGC$213.5
(2) 
MP$70.2
(1) 
(1)
Includes $14.4 million of PCRBs redeemed for which MP and AE Supply are co-obligors.
(2)
Subject to market conditions, these PCRBs are being held for future remarketing.

On May 21, 2009, 517 Penelec employees, represented by4, 2011, AE terminated its $250 million credit facility due to other available funding sources following completion of the IBEW Local 459, elected to strike. In response, on May 22, 2009, Penelec implemented its work-continuation plan to use nearly 400 non-represented employeesmerger with previous line experience and training drawn from Penelec and other FirstEnergy operations to perform service reliability and priority maintenance work in Penelec’s service territory. Penelec's IBEW Local 459 employees ratified a three-year contract agreement on July 19, 2009, and returned to work on July 20, 2009.FirstEnergy.

On June 26, 2009,17, 2011, FirstEnergy announced that sevenand certain of its union locals, representing about 2,600 employees, ratified contract extensions. The unions included employees from Penelec, Penn, CEI, OEsubsidiaries entered into two 5-year revolving credit facilities with a total borrowing capacity of $4.5 billion. These facilities consist of a $2 billion revolving credit facility for FirstEnergy and TE, along with certain power plant employees. On July 8, 2009,its regulated utility subsidiaries


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and a $2.5 billion revolving credit facility for FES and AE Supply. Prior separate facilities ($2.75 billion at FirstEnergy, announced that employees of Met-Ed represented by IBEW Local 777 ratified a two-year contract. Union members had been working without a contract since the previous agreement expired on April 30, 2009.  On December 7, 2009, FirstEnergy announced that employees of its FGCO subsidiary represented by the IBEW Local 272 voted to ratify a thirty-nine month labor agreement that runs through February of 2013. IBEW Local 272 represents 374 of 513 employees$1 billion at the Bruce Mansfield Plant in Shippingport, Pennsylvania.AE Supply, $110 million at MP, $150 million at PE and $200 million at WP) were terminated.

Smart Grid ProposalDuring the third quarter of 2011, FirstEnergy received approximately $130 million from assigning a substantially below-market, long-term fossil fuel contract to a third party. As a result, FirstEnergy entered into a new long-term contract with another supplier for replacement fuel based on current market prices. The new contract runs for nine years, which is the remaining term of the assigned contract. The transaction reduced fuel costs during the quarter by approximately $123 million.

TrAIL's primary investment, the Trans-Allegheny Interstate Line (a 500-kV transmission project that extends from Southwestern Pennsylvania through West Virginia to Northern Virginia), was completed in May 2011.

On August 6, 2009,January 26, 2012, FirstEnergy filed an applicationannounced a change to its method for economic stimulus funding with the DOE under the American Recoveryaccounting for pensions and Reinvestment Act that proposed investing $114 million on smart grid technologies to improve the reliabilityOPEB effective in 2011 (see Note 1, Organization, Basis of Presentation and interactivity of its electric distribution infrastructure in its three-state service area. The application requested $57 million, which represents halfSignificant Accounting Policies of the funding needed for targeted projects in communities served byCombined Notes to the Utilities. On October 27, 2009, FirstEnergy received notice from the DOE that its application was selected for award negotiations. However, no assurance can be givenConsolidated Financial Statements). We also disclosed that we will receive such an award. The remaining investment would be expectedmade a $600 million voluntary contribution to be recovered through customer rates. The project was approved by the NJBPU on August 6, 2009. Approval by the PPUC and the PUCO for the Pennsylvania portion and the Ohio portion, respectively, of the project is pending.

Powering our Communities Program

In September 2009, FES introduced Powering Our Communities, an innovative programpension plan earlier that offers economic support to communities in the OE, CEI and TE service areas. The program provides up-front economic support to Ohio residents and businesses that agree to purchase electric generation supply from FES through governmental aggregation programs. As of February 1, 2010, FES signed agreements with 57 area communities.

In January 2010, FES, NOPEC and GEXA Energy, NOPEC's former generation supplier, finalized agreements making FES the generation supplier for approximately 425,000 customers in the 160 Northeast Ohio communities served by NOPEC from January 1, 2010 through December 31, 2019.month.

Regulatory Matters - Ohio

Ohio Regulatory UpdateMet-Ed and Penelec Transition to Competitive Markets

In August 2009,The Pennsylvania Companies began the PUCO approvedmove to competitive markets with the applications to accelerateexpiration of the recovery of deferredrate caps on Met-Ed's and Penelec's retail generation rates on December 31, 2010. Beginning in 2011, Met-Ed and Penelec obtained their power supply from the competitive wholesale market and fully recover their generation costs primarily for distribution investments, from up to 25 years to 18 months. The principal amount plus carrying charges through August 31, 2009, for these deferrals was approximately $305 million. Accelerated recovery began September 1, 2009, and will be collected in the 18 non-summer months through May 31, 2011, which is expected to save customers approximately $320 million in carrying costs.

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On December 10, 2009, rules went into effect that set out the manner in which Ohio’s electric utilities will be required to comply with benchmarks contained in SB221 related to the employment of alternative energy resources, energy efficiency/peak demand reduction programs, greenhouse gas reporting requirements and changes to long term forecast reporting requirements. The rules 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.retail rates. The Ohio Companies, submitted an applicationPenn, WP and JCP&L previously transitioned to amend their 2009 statutory energy efficiency benchmarks to zero.  In January 2010, the PUCO approved the Ohio Companies’ request contingent upon their meeting energy efficiency programs in 2010 – 2012.competitive generation markets.

On December 15, 2009, FirstEnergy's Ohio Utilities filed three-year plans with the PUCO to offer energy efficiency programs to their customers. The filing outlined specific programs to make homes and businesses more energy efficient and reduce peak energy use.  The PUCO has set the matter for hearing on March 2, 2010.

In October 2009, the Ohio Companies filed an MRO to procure electric generation for the period beginning June 1, 2011, that would establish a CBP to secure generation supply for customers who do not shop with an alternative supplier.

In late 2009 the Ohio Companies conducted RFPs and secured RECs including solar RECs and RECs generated in Ohio, in order to meet the Ohio Companies’ alternative energy requirements established under SB221 for 2009, 2010 and 2011. As the Ohio Companies were only able to procure a portion of their solar energy resource requirements for 2009, on December 7, 2009, they filed an application with the PUCO seeking approval for a force majeure determination to reduce the 2009 solar energy resources requirement to the level of the RECs received through the RFPs. Absent this regulatory relief, the Ohio Companies may not be able to meet their 2009 statutory renewable energy benchmarks, which may result in the assessment of forfeiture by the PUCO. The PUCO has not yet ruled on that application.

Regulatory Matters - Pennsylvania

NUG Statement Compliance FilingMarginal transmission loss recovery

On March 31, 2009,3, 2010, the PPUC issued an order denying Met-Ed and Penelec submitted their 5-year NUG Statement Compliance filingthe ability to the PPUC. Both Met-Ed and Penelec proposed to reduce their CTC rate for certain customer classes with a corresponding increase in the generation rate and 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. The PPUC approved the compliance filings and the reduction in the CTC rate.

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, the Office of Small Business Advocate, Office of Consumer Advocate, York County Solid Waste and Refuse Authority, and others filed comments objecting to the above accounting method utilized by Met-Ed and Penelec. After Met-Ed and Penelec filed reply comments, the PPUC issued a Secretarial Letter on November 5, 2009 allowing parties to file reply comments to Met-Ed and Penelec’s reply comments by November 16, 2009. Reply comments were filed and the companies are awaiting further action by the PPUC.

Act 129

In 2009, the PPUC approved the company-specific energy consumption and peak demand reductions that must be achieved under Act 129, which requires electric distribution companies to reduce electricity consumption by 1% by May 31, 2011 and by 3% by May 31, 2013, and an annual system peak demand reduction of 4.5% by May 31, 2013. Costs associated with achieving the reduction will be recovered from customers. On July 1, 2009, Met-Ed, Penelec and Penn filed energy efficiency and conservation plans, which approval is pending.

Act 129 also required utilities to file with the PPUC a smart meter technology procurement and installation plan to provide for the installation of smart meter technology within 15 years. The plan filed by Met-Ed, Penelec, and Penn proposed a 24-month period to assess their needs, select 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 15 years. Met-Ed, Penelec and Penn estimate assessment period costs at approximately $29.5 million, which the Pennsylvania Companies proposed to recover through an automatic adjustment clause. A decision is pending by the presiding ALJ.

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Transmission Cost Recovery

In 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 future TSCs by December 31, 2010. Various intervenors filed complaints against those filings and the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while allowing Met-Ed to implement the June 1, 2008 rider, subject to refund. In August 2009, the ALJ issued a Recommend Decision to the PPUC approving Met-Ed’s and Penelec’s TSCs as filed and dismissing all complaints. On January 28, 2010, the PPUC adopted a motion which denies the recovery of marginal transmission losses through the TSC fortransmission service charge riders in their respective tariffs which applies to the period ofperiods including June 1, 20072008 through MarchDecember 31, 2008, and instructs2010. Subsequently, Met-Ed and Penelec to workfiled a Petition for Review with the parties and file a petition to retain any over-collection, with interest, until 2011 for the purpose of providing mitigation of future rate increases starting in 2011 for their customers.  The Companies are now awaiting an order, which is expected to be consistent with the motion. If so, Met-Ed and Penelec plan to appeal such a decision to the Commonwealth Court of Pennsylvania. AlthoughPennsylvania (Commonwealth Court) appealing the ultimte outcomePPUC's order. On June 14, 2011, the Commonwealth Court affirmed the PPUC's decision that marginal transmission losses are not recoverable as transmission costs. On July 13, 2011, Met-Ed and Penelec filed a federal complaint with the United States District Court for the Eastern District of this matter cannot be determined at this time, itPennsylvania and on the following day, filed a Petition for Allowance of Appeal to the Pennsylvania Supreme Court. Met-Ed and Penelec believe the Commonwealth Court's decision contradicts federal law and is the belief of the Companies that they should prevail in any such appealinconsistent with prior PPUC and court decisions and therefore expect to fully recover the approximately $170.5 millionrelated regulatory assets ($138.7189 million for Met-Ed and $31.8$65 million for Penelec) in marginal transmission losses. In January 2011 and continuing for 29 months, pursuant to a related PPUC order, Met-Ed and Penelec began crediting customers for the period prior to January 1, 2011.

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, subject toamounts at issue pending the outcome of the preceding related to the 2008 TSC filing described above. Although the new TSC resulted in an approximate 1% decrease in monthly bills for Penelec customers, 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. Under the proposal, monthly bills for Met-Ed’s customers would increase approximately 9.4% for the period June 2009 through May 2010.court appeals.

Default ServiceOhio Energy Efficiency and Peak Demand Reduction Portfolio Plan

On February 20, 2009, Met-EdMarch 23, 2011, the PUCO approved the three-year Energy Efficiency and Penelec filedDemand Reduction portfolio plan for the Ohio Companies. The Ohio Companies' plan was developed to comply with the PPUCEnergy Efficiency mandate in Ohio's SB 221, passed in 2008. This law requires that utilities in Ohio reduce energy usage by 22.2 percent by 2025 and peak demand by 7.75 percent by 2018, develop a generation procurementportfolio plan, covering the period January 1, 2011 through May 31, 2013. A settlement agreement was later filed on all but two issues and on November 6, 2009, the PPUC entered an Order approving the settlement and finding in favor of Met-Ed and Penelec on the two issues reserved for litigation. Generation procurement began in January 2010.meet annual benchmarks to measure progress.

NYSEG Ruling

On February 8, 2010, Penn filed withJuly 11, 2011, FirstEnergy was found to be a potentially responsible party under CERCLA indirectly liable for a portion of past and future clean-up costs at certain legacy MGP sites in New York. As a result, FirstEnergy recognized additional expense of $29 million during the PPUC a generation procurement plan covering the period June 1, 2011 through May 31, 2013. The plan is designed to provide adequate and reliable service via a prudent mixsecond quarter of long-term, short-term and spot market generation supply, as required by Act 129. The plan proposed a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. The PPUC must issue an order on the plan no later than November 8, 2010.2011.

Regulatory Matters – New Jersey

Solar Renewable Energy ProposalWest Virginia Fuel, Purchased Power Cost Decision

On March 27, 2009,December 30, 2011, MP and PE announced that the NJBPUWVPSC issued an order regarding the companies' adjustment of fuel and purchased power costs. The WVPSC's order approved JCP&L’s proposal to helpa settlement agreement between the companies, the Consumer Advocate Division, the Staff of the WVPSC and the West Virginia Energy Users Group. In the approved settlement, parties have agreed that the companies will recover an additional $19.6 million in 2012, an approximate 1.7 percent increase, the pace of solar energy project development by establishing long-term agreements to purchase and sell SRECs, which will provide a stable basis for financing solar generation projects.  In 2009, JCP&L, in collaboration with another New Jersey electric utility, announced an RFP to secure SRECs.  A total of 61 MW of solar generating capacity (42 for JCP&L) will be solicited to help meet New Jersey Renewable Portfolio Standards. The first solicitation was conducted in August 2009; subsequent solicitations will occurprimarily reflecting rising coal prices over the next three years. The costs of this program are expectedpast two years, with certain additional amounts to be fully recoverable throughrecovered over time with a per KWH rate approved by the NJBPU and applied to all customers.carrying charge.

On February 11, 2010, Standard and Poor’s downgraded the senior unsecured debt of FirstEnergy Corp. to  BB+.  As a result, pursuant to the requirements of a pre-existing NJBPU order, JCP&L filed, on February 17, a plan addressing the mitigation of any effect of the downgrade and which provided an assessment of present and future liquidity necessary to assure JCP&L’s continued payment to BGS suppliers.  The order also provides that the NJBPU should: 1) within 10 days of that filing, hold a public hearing to review the plan and consider the available options and 2) within 30 days of that filing issue an order with respect to the matter.  At this time, the public hearing has not been scheduled and FirstEnergy and JCP&L cannot determine the impact, if any, these proceedings will have on their operations.

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FIRSTENERGY’S BUSINESS

We are a diversified energy company headquartered in Akron, Ohio, that operates primarily through two core business segments (see “Results of Operations”). Financial information for each of FirstEnergy’s reportable segments is presented in the following table. With the completion of transitionthe AE merger in the first quarter of 2011, FirstEnergy reorganized its management structure, which resulted in changes to a fully competitiveits operating segments to be consistent with the manner in which management views the business. The new structure supports the combined company's primary operations - distribution, transmission, generation marketand the marketing and sale of its products. The external segment reporting is consistent with the internal financial reporting used by FirstEnergy's chief executive


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officer (its chief operating decision maker) to regularly assess the performance of the business and allocate resources. FirstEnergy now has three reportable operating segments - Regulated Distribution, Regulated Independent Transmission and Competitive Energy Services.
Prior to the change in Ohio in 2009, the former Ohio Transitional Generation Services segmentcomposition of business segments, FirstEnergy's business was combined with thecomprised of two reportable operating segments. The Energy Delivery Services segment consistent with how management viewswas comprised of FirstEnergy's then eight existing utility operating companies that transmit and distribute electricity to customers and purchase power to serve their POLR and default service requirements. The Competitive Energy Services segment was comprised of FES, which supplies electric power to end-use customers through retail and wholesale arrangements. The “Other/Corporate” amounts consisted of corporate items and other businesses that were below the business.quantifiable threshold for separate disclosure. Disclosures for FirstEnergy’sFirstEnergy's operating segments for 2008 and 20072010 have been reclassified to conform to the 2009revised presentation.
The changes in FirstEnergy's reportable segments during 2011 consisted primarily of the following:
Energy Delivery Services was renamed Regulated Distribution and the operations of MP, PE and WP, which were acquired as part of the merger with AE, and certain regulatory asset recovery mechanisms formerly included in the “Other/Corporate” segment, were placed into this segment.
A new Regulated Independent Transmission segment was created consisting of ATSI, and the operations of TrAIL and FirstEnergy's interest in PATH; TrAIL and PATH were acquired as part of the merger with AE. The transmission assets and operations of JCP&L, Met-Ed, Penelec, MP, PE and WP remained within the Regulated Distribution segment.
AE Supply, an operator of generation facilities that was acquired as part of the merger with AE, was placed into the Competitive Energy Services segment with FES.

·
Energy Delivery Services transmits 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 PLR 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.Regulated Distribution distributes electricity through our ten utility distribution companies, serving approximately 6 million customers within 67,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also includes the transmission operations of JCP&L, Met-Ed, Penelec, WP, MP and PE and the regulated electric generation facilities in West Virginia and New Jersey which MP and JCP&L, respectively, own or contractually control. 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.

The service areas of our regulated distribution utilities are summarized below:

Company Area Served Customers Served
OE
 
Central and Northeastern Ohio
 
1,038,000
1,032,000
PennWestern Pennsylvania161,000
CEINortheastern Ohio747,000
TENorthwestern Ohio309,000
JCP&LNorthern, Western and East Central New Jersey1,099,000
Met-EdEastern Pennsylvania553,000
PenelecWestern Pennsylvania590,000
WPSouthwest, South Central and Northern Pennsylvania718,000
MPNorthern, Central and Southeastern West Virginia387,000
PEWestern Maryland and Eastern West Virginia390,000
    
Penn
5,986,000
Western Pennsylvania
160,000
CEI
Northeastern Ohio
754,000
TE
Northwestern Ohio
310,000
JCP&L
Northern, Western and East
Central New Jersey
1,095,000
Met-Ed
Eastern Pennsylvania
551,000
Penelec
Western Pennsylvania
590,000
ATSI
Service areas of OE, Penn,
CEI and TE


·
Competitive Energy Services supplies electric power to end-use customers through retail and wholesale arrangements, including associated company power sales to meet all or a portion of the PLR and default service requirements of our Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Maryland and Michigan. This business segment owns or leases and operates 19 generating facilities with a net demonstrated capacity of 13,710 MWs 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 relatedRegulated Independent Transmission transmits electricity through transmission lines and its revenues are primarily derived from a formulaic rate that recovers 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.

PROPOSED MERGER WITH ALLEGHENY

Proposed Merger with Allegheny Energy, Inc.

On February 10, 2010, we entered into a Merger Agreement with Allegheny the consummation of which will result, among other things, in our becoming an electric utility holding company for:

·generation subsidiaries owning or controlling approximately 24,000 MWs of generating capacity from a diversified mix of regional coal, nuclear, natural gas, oil and renewable power,

·ten regulated electric distribution subsidiaries providing electric service to more than six million customers in Pennsylvania, Ohio, Maryland, New Jersey, New York, Virginia and West Virginia, and

·transmission subsidiaries owning over 20,000 miles of high-voltage lines connecting the Midwest and Mid-Atlantic.

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Upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will merge with and into Allegheny with Allegheny continuing as the surviving corporation and a wholly-owned subsidiary of FirstEnergy.  Pursuant to the Merger Agreement, upon the closing of the merger, each issued and outstanding share of Allegheny 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. Completion of the merger is conditioned upon, among other things, shareholder approval of both companies 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 Maryland Public Service Commission, PPUC, the Virginia State Corporation Commission and the West Virginia Public Service Commission. We anticipate that the necessary approvals will be obtained within 12 to 14 months. The Merger Agreement contains certain termination rightsreturn on investment for both us and Allegheny, and further provides for the payment of fees and expenses upon termination under specified circumstances. Further information concerning the proposed merger will be included in a joint proxy statement/prospectus contained in the registration statement on Form S-4 to be filed by us with the SECcapital expenditures in connection with TrAIL, PATH and other projects, revenues from providing transmission services to electric energy providers and power marketers, and revenues from operating a portion of the merger.FirstEnergy transmission system. Its results reflect the net transmission expenses related to the delivery of the respective generation loads.

PriorCompetitive Energy Services supplies, through FES and AE Supply, electric power to end-use customers through retail and wholesale arrangements, including competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland and the provision of partial POLR and default service for some utilities in Ohio, Pennsylvania and Maryland, including but not limited to the merger, we and Allegheny will continueUtilities. This segment controls approximately 17,000 MWs of capacity (excluding approximately 2,700 MWs from unregulated plants expected to operate as separate companies. Accordingly, except for specific referencesbe closed by September 1, 2012) (see Note 11, Impairment of Long-Lived Assets of the Combined Notes to the pending merger,Consolidated Financial Statements) and also purchases electricity to meet sales obligations. The segment's net income is primarily derived from electric generation sales less the descriptionsrelated costs of our strategyelectricity generation, including purchased power and outlooknet transmission (including congestion) and the risksancillary costs charged by PJM and challenges we face, and the discussion and analysis of our results of operations and financial condition set forth below relate solelyMISO (prior to FirstEnergy.  Details regarding the pending merger are discussed in Note 21June 1, 2011)


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to deliver energy to the consolidated financial statements. segment's customers.

Other/Corporate contains corporate items and other businesses that are below the quantifiable threshold for separate disclosure as a reportable segment. (See Note 19, Segment Information of the Combined Notes to the Consolidated Financial Statements for further information on FirstEnergy's reportable operating segments.)
STRATEGY AND OUTLOOK

We continueFirstEnergy's vision is to focus onbe a leading regional energy provider, recognized for operational excellence, outstanding customer service and our commitment to safety; the primary objectiveschoice for long-term growth, investment value and financial strength; and a company driven by the leadership, skills, diversity and character of our employees.

FirstEnergy has grown over the last 15 years through several strategic mergers and asset transactions. Our most recent merger with Allegheny was completed in February 2011, significantly increasing our customer base and generating capacity and accelerating our movement further into eastern competitive markets. Also during 2011, we have developed that support our business fundamentals – safety, generation, reliability, transitioningcompleted the transition to competitive markets managingin Pennsylvania and moved our liquidity, and growing earnings. To achieve these objectives,ATSI assets into PJM, so that we are pursuing the following strategies:now operate within a single regional transmission system.

§strengthening our safety focus;
§maximizing the utilization of our generating fleet;
§meeting our transmission and distribution reliability goals;
§managing the transition to competitive generation market prices in Ohio and Pennsylvania;
§executing our direct-to-customer retail sales strategy;
§maintaining adequate and ready access to cash resources; and
§achieving our financial goals and commitments to shareholders.

2009 was a difficult year forFirstEnergy is uniquely positioned as the U.S. economy due to the ongoing effects of the recession. In the region FirstEnergy serves, this was evidenced by reduced sales, particularly in the industrial sector, and very soft wholesale market power prices when compared to 2008. We responded, in part, by making adjustments to both our operational and capital spending plans, as well as our financing plans. Despite these challenges, we continued to make solid progress toward achieving our overall operational and financial goals.

We began implementation of our long-term strategic plans during the past several years. Our gradual progression to competitive generation marketsnation's largest contiguous electric system, with complementary assets across our tri-state service territory and other strategies to improve performance and deliver consistent financial results is characterized by several important transition periods:

2007 and 2008

In 2007, we successfully transitioned Penn to market-based retail rates for generation service through a competitive, wholesale power supply procurement process. During 2007 we also completed comprehensive rate cases for Met-Ed and Penelec, which better aligned their transmission and distribution rates with their rate base and costs to serve customers. For generation service, Met-Ed and Penelec received partial requirements for their PLR service from FES. Also during 2007, the Ohio Companies filed an application for an increase in electric distribution rates with the PUCO to support a distribution rate increase. In 2009, the PUCO granted the Ohio Companies' application to increase electric distribution rates by $136.6 million. These increases went into effect during 2009.

We continued our successful “mining our assets” program, through which we increased the net-generating capacity at several facilities through cost-effective unit upgrades. In 2008, we achieved record generation output of 82.4 billion KWH. Our generation growth strategy is to continue to implement low cost, incremental upgrades to existing facilities, complemented by strategic asset purchases, rather than making substantial investments in new coal or nuclear baseload capacity with very long lead times to construct.

We made several strategic investments in 2008, including the purchase of the partially complete Fremont Energy Center, which 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. We expect to complete construction by the end of 2010.

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In mid-2008, we also entered into a joint venture to acquire a majority stake in the Signal Peak coal mining project. As part of that transaction, we also entered into a 15-year agreement to purchase up to 10 million tons of coal annually from the mine, securing a long-term western fuel supply at attractive prices. The higher Btu content of Signal Peak coal versus Powder River Basin coal is expected to help avoid fossil plant derates of approximately 170 MW and help support our incremental generation expansion plans. The burning of Signal Peak coal is also expected to improve the performance of some of our older generating units, which will factor into our decision making process regarding potential future plant shutdowns. Signal Peak began commercial operation in December 2009. Although, we have experienced some issues with the start-up of commercial operations, we believe those issues will be resolved and Signal Peak is expected to achieve its production goals for the year.  In the fourth quarter of 2008, FES assigned two existing Powder River Basin contracts to a third party in order to reduce its forecasted 2010 long coal position as a result of expected deliveries from Signal Peak.

In July 2008, we filed both a comprehensive ESP and MRO with the PUCO. In November 2008, the PUCO issued an order denying the MRO. In December 2008, the PUCO approved, but substantially modified, our ESP. After determining that the plan no longer maintained a reasonable balance between providing customers with continued rate stability and a fair return on the Ohio Companies’ investments to serve customers, we withdrew our application for the ESP as allowed by law (see Regulatory Matters – Ohio).

2009 and 2010

In 2009, our total generation output of 65.9 billion KWH reflected the economic realities of the continued recession coupled with mild weather, particularly during the summer months. Due to the continued implementation of our retail strategy, which will concentrate on direct sales and governmental aggregation and de-emphasize the wholesale market, we expect a significant increase in our generation output in 2010. Distribution rate increases became effective for OE and TE in January 2009 and for CEI in May 2009, as a result of rate cases filed in 2007. Transition cost recovery related to the Ohio Companies’ transition to a competitive generation market ended for OE and TE on December 31, 2008. Additionally, FES assumed their third party partial requirements contracts and now expects to provide Met-Ed and Penelec with their complete PLR and default service load through the end of 2010 when their current rate caps expire and they transition to procuring their generation requirements at competitive market prices.

On February 19, 2009, the Ohio Companies filed an amended ESP application, including a Stipulation and Recommendation that was signed by the Ohio Companies, the Staff of the PUCO, and many of the intervening parties representing a diverse range of interests and on February 26, 2009 filed a Supplemental Stipulation supported by nearly every party in the case, which the PUCO approved in March 2009 (see Regulatory Matters – Ohio). The Amended ESP included a May 2009 auction to secure full requirements generation supply and pricing for the Ohio Companies for the period June 1, 2009 through May 31, 2011. The auction resulted in an average weighted wholesale price for generation and transmission of 6.15 cents per KWH. FES was a successful bidder for 51% of the Ohio Companies PLR load.

Following the May 2009 auction, FES accelerated the execution of its retail strategy, described above, to directly acquire and serve customers of the Ohio Companies, including select large commercial and industrial customers. Through December 31, 2009, FES entered into agreements with 60 area communities under governmental aggregation programs, representing approximately 580,000 residential and small commercial customers inside of our Ohio franchise territories.  As of December 31, 2009, FES supplied 77% of the PLR load.

In August 2009, we filed an application with the FERC for approval to consolidate our ATSI transmission assets and operations currently dedicated to MISO into PJM. On December 17, 2009, FERC issued an order approving the integration and outlining the terms required for the move, which is expected to be complete by June 1, 2011. On December 18, 2009, ATSI announced it had signed an agreement to join PJM. In December 2009, we also announced that an agreement in principle had been reached to sell the 340-MW Sumpter Plant which is located in MISO. The sale is expected to close in the first quarter of 2010.

Total distribution sales in 2009 were 102 million MWH, down from 112 million MWH in 2008. This decrease was due to the effects of the recession, primarily in reduced industrial sales, coupled with mild weather.

As we look to 2010 and beyond, we expect to continue our focus on operational excellence with an emphasis on continuous improvement in our core businesses to position for success during the next phase of the market recovery. This includes ongoing incremental investment in projects to increase our generation capacity and energy production capability as well as programs to continue to improve transmission and distribution system reliability and customer service.

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2011 and Beyond

Another major transition period for FirstEnergy will begin in 2011 as the current cap on Met-Ed’s and Penelec’s retail generation rates is expected to expire. Beginning in 2011, Met-Ed and Penelec have approval from the PPUC to obtain their power supply from the competitive wholesale market and fully recover their generation costs through retail rates. As a result, FES plans to redeploy the power currently sold to Met-Ed and Penelec primarily to retail customers located in and near our generation footprint and into local regional auctions and RFPs for PLR service, with the remainder available for sale in the wholesale market.

In Ohio, we filed an application for an MRO with the PUCO in October 2009, which would establish generation rates for the Ohio Companies beginning June 1, 2011, using a descending clock-style auction similar in all material respects to that used in the May 2009 auction process. Pursuant to SB221, the PUCO has 90 days from the date of the application to determine whether the MRO meets certain statutory requirements. Although the Ohio Companies requested a PUCO determination by January 18, 2010, on February 3, 2010, the PUCO announced that its determination would be delayed. Under a determination that such statutory requirements are met, the Ohio Companies would be able to implement the MRO and conduct the CBP.

We will continue our efforts to extract additional production capability from existing generating plants as discussed under “Capital Expenditures Outlook” below and maintain the financial and strategic flexibility necessary to thrive in the competitive marketplace.

As discussed above, our strategy is focused on maximizing the earnings potential from our unregulated FES operations and maintaining stable earnings growth from our regulated utility operations.  In addition, if approvals for the pending merger with Allegheny have been obtained and the merger is consummated in early to mid-2011 as we currently expect, the work of integrating Allegheny and its operations and generation, transmission and distribution delivery operations. These assets with our own will beginare in earnest.  We expect that those efforts will enhance our ability to achieve our strategic goals as discussed above.a prime location of PJM's competitive markets.

Our substantial regulated operations include 10 distribution utilities serving a balanced base of nearly 6 million customers across 5 states. We are also one of the largest owners of transmission assets in PJM with nearly 20,000 miles of high-voltage lines, including two independent transmission companies with significant assets. Combined, our utilities and transmission operations provide financial stability with strong cash flow and dividend support to FirstEnergy.

Our market-focused business model integrates more than 17,000 MWs of competitive generation, excluding approximately 2,700 MWs from unregulated plants expected to be closed by September 1, 2012, and are subject to review by PJM for reliability impacts(see Note 16, Commitment, Guarantees and Contingencies, regarding PJM's review of the our plans), with a multi-channel retail sales platform, providing a higher value for every MWH we generate. We primarily target customers in competitive markets close to our generation assets.

We believe we are well-positioned for upcoming environmental changes due to the considerable investments we have made in recent years to diversify our generation fleet and improve its environmental performance. As a result of the MATS rules recently finalized by the EPA, and other previously announced environmental regulations, FirstEnergy announced in early 2012 its intent to retire nine older coal-fired power plants, totaling 3,349 MW, located in Ohio, Pennsylvania, Maryland and West Virginia by September 1, 2012. When the retired fossil plants are removed from our fleet, nearly 100% percent of our generation output will be from either low or non-emitting facilities, including nuclear, hydro, natural gas and scrubbed coal units. This further positions our fleet to deliver superior value in the future.

We continue to face challenges related to macro-economic factors. These include slow economic recovery across portions of our service territory, which affect our distribution deliveries volumes to residential, commercial and industrial customers, and depressed natural gas and wholesale electricity prices, which affect revenues from our competitive retail business and generation fleet. However, we believe we are one of the better positioned companies in our industry to benefit from eventual increases in energy and capacity prices as economic conditions improve.

Financial Outlook

In responseWe intend to the unprecedented volatility in themanage our operating and capital and credit markets that began in late 2008 and our increased risk exposure to the commodity markets that resulted from the outcome of the Ohio CBP, we carefully assessed our exposure to counterparty credit risk, our access to funds in the capital and credit markets, and market-related changes in the value of our postretirement benefit trusts, nuclear decommissioning trusts and other investments. We have taken steps to strengthen our liquidity position and provide additional flexibility to meet our anticipated obligations and those of our subsidiaries.

These actions included spending reductions of more than $600 million in 2009 compared to 2008 levels through measured and appropriate changes in capital and operation and maintenance expenditures.  In addition, we adjusted the construction schedule for the $1.8 billion AQC project at our W.H. Sammis Plantcosts in order to delay certain costs fromachieve our 2009 budget while still targeting our completion deadline by the end of 2010.financial goals and commitment to shareholders.

We completed significant financing activities at our regulated utilities of $2.2 billion as well as issuing 5, 12 and 30-year unsecured senior notes totaling $1.5 billion at FES. We also completed refinancing $518 million of variable rate debt to fixed rate debt, and made a voluntary contribution of $500 million in September 2009 to our pension plan. 2009 cash flow from operations was strong at $2.5 billion

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. As a result, FirstEnergy may be required to post up to $48 million of collateral (see Note 15(B)).  Moody's and Fitch affirmed the ratings and stable outlook of FirstEnergy and its subsidiaries on February 11, 2010.

Our financial strategy focuses on reducing debt, a minimum of $500 million during 2010.  We are also focusing on delivering consistent financial results, improving financial strength and flexibility, deploying cash as effectively as possible, and improving our current credit metrics.

Positive earnings drivers in 2010 are expected to include:

·Increased FES commodity margin from implementation of the retail strategy and the restructuring of the PJM PLR contracts;

·Increased distribution revenues from projected sales of 110 million MWH in 2010 vs. 102 million MWH in 2009, and a full year of both the distribution rate increase and Delivery Service Improvement Rider in Ohio;

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·A full year of operation and maintenance cost savings that resulted from 2009 staffing adjustments, changes in our compensation structure, fossil plant outage schedule changes and general cost-saving measures; and

·Reduced costs from one less nuclear refueling outage in 2010 vs. 2009.

Negative earnings drivers in 2010 are expected to include:

·Reduced gains from sale of nuclear decommissioning trust investments in 2009;

·Reduced RTC margin for CEI:

·The absence of significant favorable tax settlements in 2010 compared to 2009; and

·Increased benefit and financing costs, general taxes and depreciation expense.

Our liquidity position remains strong, with access to more than $3.3 approximately $49 million of short-term cash investments and over $4.3 billion of available liquidity of which approximately $2.5 billion was available as of January 31, 2010. We intend to continue to fund our capital requirements through cash generated from operations.

A driver for longer-term earnings growth is our continued effort to improve the utilization and output of our generation fleet. During 2010 we plan to invest approximately $646 million in our regulated energy delivery services business2012.

Positive earnings drivers for 2011 could2012 are expected to include:

·
▪The December 31, 2010 expiration of FES’ contracts to serve Met-Ed and Penelec’s generation requirements. In 2011, 100% ofA full year contribution from the generation output at FES will be priced at market;Allegheny merger;

·
▪Potentially increased distribution deliveries tiedHigher competitive retail revenues as a result of continued growth in the business;

▪Lower fuel and operation and maintenance expenses due to an economic recovery;the retirement of certain coal-fired plants in 2012 and from a continued focus on controlling our costs; and

·
▪Incremental Signal Peak coal production and price improvementReduced interest expense as a result of debt redemptions during 2011.

Negative earnings drivers for 2011 could2012 are expected to include:

·
▪Increased nuclear fuel costsLower margins for our competitive energy service business from depressed market prices of power and coal contract pricing adjustments;lower capacity


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prices resulting from the PJM RPM auction beginning June 1, 2012;

·
▪Pressure to maintain O&M cost reductions vs. 2010Higher gross receipts taxes associated with a potentially improving economyincreased competitive retail sales in Pennsylvania; and

·
▪Increased depreciation and general taxes and lower capitalized interest resultingexpenses from completion of our Sammis AQC and Fremont constructioncapital projects that were placed in service during 2011.

On January 5, 2012, we made a $600 million voluntary contribution to our pension plan bringing its funding level to 90% on an accumulated benefit obligation basis.

Capital Expenditures Outlook

Our capital expenditure forecastexpenditures in 2012 are estimated to be $2.1 billion (excluding nuclear fuel), a decrease of approximately $393 million from 2011. In addition to internal sources to fund capital requirements for 2010 is approximately $1.65 billion.2012 and beyond, FirstEnergy expects to rely on external sources of funds.

Capital expenditures for our competitive energy services businessRegulated Distribution segment are forecast to decrease by $63 million in 2012 from $1.1 billion in 2011. The expected decrease primarily reflects the absence of storm restoration costs related to Hurricane Irene and the October 2011 snowstorm. For our Regulated Independent Transmission segment, capital expenditures are expected to hold steadydecrease to $105 million in 2012 from 2009$190 million in 2011. The decrease reflects the completion of TrAIL's 500-kV transmission line in 2011.

Expenditures for Ohio and Pennsylvania energy efficiency and advanced metering initiatives are expected to 2010 at $467be primarily recovered from distribution customers and federal stimulus funding. Other capital investments in our transmission and distribution infrastructure are planned to satisfy transmission capacity and reliability requirements, connect new load delivery and wholesale generation points, and achieve cost-effective improvements in the reliability of our service.

For our Competitive Energy Services segment, capital expenditures are expected to increase by $32 million exclusiveto $803 million in 2012. The main drivers of Sammis AQC project, the Burger Biomass conversion and Norton, and the Fremont facility. That level spending plan includes $65 million for the Davis-Besseincrease include steam generator replacement expected to be completed in 2014.projects at Davis-Besse and Beaver Valley Unit 2 and turbine rotor replacement projects at Perry and Beaver Valley Unit 2. Other planned expendituresgeneration investments provide for maintainingmaintenance of critical generation assets, delivering operational improvements to enhance reliability, supporting environmental compliance, and supportingadvancing our generation to market strategy.

This is the final year for work on the Sammis AQC project, which is expected to go in service at the end of 2010. To date, this initiative has cost just under $1.58 billion, with an additional $241 million planned in 2010. Expenditures on the Burger Biomass conversion project get underway in 2010 with $16 million planned. The project is expected to be completed by December 2012. We plan to spend $150 million in 2010 on the Fremont facility and anticipate that work will be completed by the end of the year.

For our regulated operations, capital expenditures are forecast to be $646 million in 2010, primarily in support of transmission and distribution reliability. The spending plan also includes projects in Ohio and Pennsylvania for Energy Efficiency and Advanced Metering initiatives, which are expected to be partially reimbursed through federal stimulus funding.

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The anticipated 2010 capital spend for the Regional Transmission Expansion initiative is $78 million. This initiative is focused on meeting NERC, Reliability First Corporation, PJM and FirstEnergy planning criteria. In addition, there are projects associated with the connection of new retail and wholesale load delivery points, transition to PJM market, and projects connecting new wholesale generation connection points.

For 2011 through 2014,2013, we anticipate average annualbaseline capital expenditures of approximately $1.2$2.0 billion, exclusive ofwhich exclude any potential additional strategic opportunities, future mandated spending, energy efficiency or new mandated spending.environmental spending relating to MATS. Planned capital initiatives are intended to promote reliability, improve operations, and support current environmental and energy efficiency proposals.

Actual capital spending for 2009 and projected capital spending for 2010 is as follows:

Projected Capital Spending
by Business Unit
 2009  2010 
  (In millions) 
Energy Delivery $687  $646 
Nuclear  259   265 
Fossil  199   186 
FES Other  9   16 
Corporate  46   52 
Sammis AQC  437   241 
Subtotal $1,637  $1,406 
Fremont Facility  51   150 
Burger Biomass and Norton  38   17 
Transmission Expansion  44   78 
Total Capital $1,770  $1,651 
directives.

Environmental Outlook

At FirstEnergy, weWe continually strive to enhance environmental protection and remain good stewards of our natural resources. We allocatedevote significant resources to support our environmental compliance efforts, and our employees share both a commitment to, and accountability for, our environmental performance. Our corporate focus on continuous improvement is integral to our environmental performance.programs.

Recent action underscores our commitment to enhancing our environmental stewardship throughout our entire organization as well as mitigating the company’s exposure to existing and anticipated environmental laws and regulations.

In April, 2009, we announced our intention to convert our R.E. Burger Plant in Shadyside, Ohio from a facility that generates electricity by burning coal to one that will utilize renewable biomass. When completed, Burger will be one of the largest renewable facilities of its kind in the world. In September 2009, we announced plans to complete construction of the Fremont Energy Center, a 707-MW natural-gas fired peaking plant located in Fremont, Ohio, by the end of 2010. And in November 2009, we purchased the rights to develop a compressed-air electric generating plant in Norton, Ohio. This technology would essentially operate like a large battery with the ability to store energy when there is low demand and then use it when needed. This is especially important for the storage of energy generated from intermittent renewable sources of energy – such as wind and solar – as they do not always produce energy when demand is high. Together, these three low-emitting projects (Burger, Fremont, and Norton) are part of our overall environmental strategy, which includes continued investment in renewable and low-emitting energy resources.

We have spent more than $7$10 billion on environmental protection efforts since the initial passage of the Clean Air Act became lawand Water Acts in 1970,the 1970s, and these investments are making a difference.demonstrate our continuing commitment to the environment. Recent investments of $3.0 billion at our Hatfield, Fort Martin and Sammis Plants, further reduced emissions of SO2 by over 95%, and NOx by at least 64% at these facilities. Since 1990, we have reduced emissions of nitrogen oxides (NOx)NOx by more than 72% sulfur dioxide (SO2)76%, SO2 by more than 69%86%, and mercury by about 47%approximately 56%.  Also, our CO2 emission rate, in pounds of CO2 per kWh, has dropped by 19 percent through this period. Based on this progress, emission rates for our power plants are significantly lower than the regional average.

To further enhance our environmental performance, we have implemented our AQC plan. The plan includes projects designed to ensure that all of the facilities in our generation fleet are operated in compliance with all applicable emissions standards and limits, including NOx SO2 and particulate. It also fulfills the requirements imposed by the 2005 Sammis Consent Decree that resolved Sammis NSR litigation. At the end of 2010, we will have invested approximately $1.8 billion at our W.H. Sammis Plant in Stratton, Ohio, to further reduce emissions of SO2 and NOx. This multi-year environmental retrofit project, which began in 2006 and is expected to be completed in 2010, is designed to reduce the plant’s SO2 emissions by 95% and NOx by at least 64%. This is one of the largest environmental retrofit projects in the nation.

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By yearend, we expect approximately 70% of our generation fleet to be non emitting or low emitting generation.  Over 52% of our coal-fired generating fleet will have full NOx and SO2 equipment controls thus significantly decreasing our exposure to the volatile emission allowance market for NOx and SO2 and potential future environmental requirements.

One of the key issues facing our company and industry is global climate change related mandates. Lawmakers at the state and federal level are exploring and implementing a wide range of responses. We believe our generation fleet is very well positioned to be successfully competitive in a carbon-constrained economy.  In addition, we believe the proposed merger with Allegheny, if consummated, will enhance our environmental profile as it will result in our having an even more diverse mix of fully-scrubbed baseload fossil, non-emitting nuclear and renewable generation, including large-scale storage.

We have taken aggressive steps over the past two decades that have increased our generating capacity without adding to overall CO2 CO2 emissions. For example, since 1990, we have reconfigured our fleet by retiring nearly 700 megawatts1,312 MWs and committing to retire in the near future 3,349 MWs of older, coal-based generation and adding more than 1,800 megawattsMWs of non-emitting nuclear capacity. Through these and other actions, we have increased our generating capacity by nearly 15% over the same period while avoiding some 350over 370 million metric tons of CO2CO2 emissions. Today, nearly 40% of our electricity is generated without emitting CO2 – a key advantage that will help us meet the challenge of future government climate change mandates. And with recent announcements in 2009, including the expanded use of renewable energy, energy storage and natural gas, our CO2 emission rate will decline even further in the future.

Moreover, weWe have taken a leadership role in pursuing new ventures to test and testing and developingdevelop new technologies that show promise in achievingmay achieve additional reductions in CO2CO2 emissions. These include:

·Bringing online 132.5 MW of wind generation in 2009 and we now sell over 1 million MWhSales of over 1 million MWH per year of wind generation.

·Testing of CO2 sequestration at our R.E. Burger Plant. The results of this testing will help us gain a better understanding of the potential for geological storage of CO2.
CO2 sequestration testing to gain a better understanding of the potential for geological storage of CO2.

·
Supporting afforestation - growing forests on non-forested land - and other efforts designed to remove CO2Supporting afforestation – growing forests on non-forested land – and other efforts designed to remove CO2 from the environment.

·Participating in the U.S. EPA’s SF6 (sulfur hexafluoride) Emissions Reduction Partnership for Electric Power Systems since its inception in 1998.  Since then, we have reduced emissions of SF6 by nearly 20 metric tons, resulting in an equivalent reduction of nearly 430,000 tons of CO2.
Reducing emissions of SF6 (sulfur hexafluoride) by nearly 15 metric tons, resulting in an equivalent reduction of nearly 315,000 metric tons of CO2, through the EPA's SF6 Emissions Reduction Partnership for Electric Power Systems.



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Supporting research to develop and evaluate cost effective sorbent materials for CO2 capture including work by EPRI and The University of Akron.

·Supporting research to develop and evaluate cost effective sorbent materials for CO2 capture including work by Powerspan at the Burger Plant and the University of Akron.

In addition, we willWe remain actively engaged in the federal and state debate over future environmental requirements and legislation, especially those dealing with global climate change.legislation. We are committed to workingactively work with policy makers and regulators to develop fair and reasonable legislation,requirements, with the goal of reducing global emissions while minimizing the economic impact on our customers. Due to the significant uncertainty as to the final form or timing of any sucha significant number of regulations and legislation at both the federal and state levels, it makes it difficultwe are unable to determine the potential impact and risks associated with GHG emissionsall future environmental requirements. The CSAPR was stayed at the end of 2011 and the federal appeals court reviewing CSAPR has scheduled an April 13, 2012 hearing. The new MATS were finalized at the end of 2011, which resulted in our decision to retire nine older coal-fired generation plants by September 1, 2012. Our current estimate is that it may cost approximately $1.3 - $1.7 billion to bring our remaining units into compliance.

We also have a long history of supporting research in distributed energy resources. Distributed energy resources include fuel cells, solar and wind systems or energy storage technologies located close to the customer or direct control of customer loads to provide alternatives or enhancements to the traditional electric power system. We are testing the world's largest utility-scale fuel cell system to determine its feasibility for augmenting generating capacity during summer peak-use periods. Through a partnership with EPRI, the Cuyahoga Valley National Park, the Department of Defense and Case Western Reserve University, two solid-oxide fuel cells were installed as part of a test program to explore the technology and the environmental benefits of distributed generation.

We are also evaluating the impact of distributed energy storage on the distribution system through analysis and field demonstrations of advanced battery technologies. Integrated direct load control technology withFirstEnergy's EasyGreen® load-management program utilizes two-way communication capability is being installed on customers’with customers' non-critical equipment, such as air conditioners in New Jersey and Pennsylvania, to help manage peak loading on the electric distribution system.

We are equally committed internallyhave also made an online interactive energy efficiency tool, Home Energy Analyzer, available to environmental performance throughout our entire organization, including our newest facility, a “green” office building in Akron that incorporates a wide range of innovative, environmentally sound features (pictured below).  In December, this building was awarded Gold Level certification by the U.S. Green Building Council’s Leadership in Energy and Environmental Design (LEED) program, making this campus the largest office building in northeast Ohiocustomers to receive this highly-prized designation.

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Our efforts to protect the environment combine innovative technologies with proven and effective work processes. For example, we are expanding an environmental management system that tracks thousands of environmental commitments and provides up-to-date information to responsible parties on compliance issues and deadlines. This system allows us to more efficiently maintain our compliance with environmental standards.

The company also uses a rigorous compliance assistance program. Company personnel continually audit all of our facilities, from generating plants to office buildings, and conduct a top-to-bottom review of the entire operation to check on compliance with company environmental policy and environmental regulation in addition to identifying best environmental practices.

Achieving Our Vision

Our success in these and other key areas will help us continue to achieve our vision of being a leading regional energy provider, recognized for operational excellence, outstanding customer service and our commitment to safety; the choice for long-term growth, investment value and financial strength; and a company driven by the leadership, skills, diversity and character of our employees.electricity use reduction goals.

RISKSRegulated Commodity Sourcing
Certain of the Utilities have default service obligations to provide power to non-shopping customers who have elected to continue to receive service under regulated retail tariffs. The volume of these sales can vary depending on the level of shopping that occurs. Supply plans vary by state and by service territory. JCP&L’s default service or BGS supply is secured through a statewide competitive procurement process approved by the NJBPU. The Ohio Companies', Pennsylvania Companies' and PE's Maryland default service supplies are provided through a competitive procurement process approved by the PUCO (under the ESP), PPUC (under the DSP) and MDPSC (under the SOS), respectively. If any supplier fails to deliver power to any one of those Utilities’ service areas, the Utility serving that area may need to procure the required power in the market in their role as a POLR. West Virginia electric generation continues to be regulated by the WVPSC.
Unregulated Commodity Sourcing
The Competitive Energy Services segment, through FES and AE Supply, provides energy and energy related services, including the generation and sale of electricity and energy planning and procurement through retail and wholesale competitive supply arrangements. FES supplies the power requirements of its competitive load-serving obligations through a combination of subsidiary-owned generation, non-affiliated contracts and spot market transactions.
FES and AE Supply have retail and wholesale competitive load-serving obligations in Ohio, Pennsylvania, Illinois, Maryland, Michigan and New Jersey, serving both affiliated and non-affiliated companies. FES and AE Supply provide energy products and services to customers under various POLR, shopping, competitive-bid and non-affiliated contractual obligations. Geographically, most of FES’ and AE Supply's obligations are in the PJM market area where all of its respective generation facilities are located.
Regional Reliability
All of FirstEnergy's facilities are located within PJM and operate under the reliability oversight of a regional entity known as RFC. This regional entity operates under the oversight of the NERC in accordance with a Delegation Agreement approved by the FERC. RFC began operations under the NERC on January 1, 2006. On July 20, 2006, the NERC was certified by the FERC as the ERO


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in the United States pursuant to Section 215 of the FPA and RFC was certified as a regional entity.
Competition
As a result of actions taken by state legislative bodies, major changes in the electric utility business have occurred in portions of the United States, including Ohio, New Jersey, Pennsylvania and Maryland, where most of FirstEnergy utility subsidiaries operate. These changes have altered the way traditional integrated utilities conduct their business. FirstEnergy has aligned its business units to participate in the competitive electricity marketplace (see Management's Discussion and Analysis for more information regarding FirstEnergy's Competitive Energy Services segment).
FirstEnergy's Competitive Energy Services segment participates in deregulated energy markets in Ohio, Pennsylvania, Maryland, Michigan, New Jersey and Illinois, through FES and AE Supply. In these markets, the Competitive Energy Services segment competes: (1) to provide retail generation service directly to end users; (2) to provide wholesale generation service to utilities, municipalities and co-operatives, which, in turn, resell to their end users, and (3) in the wholesale market. The success of the Competitive Energy Services segment is driven by its ability to successfully compete against other retail markets and/or generators and to produce revenues that exceed costs.
Seasonality
The sale of electric power is generally a seasonal business and weather patterns can have a material impact on FirstEnergy’s operating results. Demand for electricity in our service territories historically peaks during the summer and winter months, with market prices also generally peaking at that time. Accordingly, FirstEnergy’s annual results of operations and liquidity position may depend disproportionately on its operating performance during the summer and winter. Mild weather conditions may result in lower power sales and consequently lower earnings.
Research and Development
The Utilities, FES, FGCO and FENOC participate in the funding of EPRI, which was formed for the purpose of expanding electric R&D under the voluntary sponsorship of the nation’s electric utility industry — public, private and cooperative. Its goal is to mutually benefit utilities and their customers by promoting the development of new and improved technologies to help the utility industry meet present and future electric energy needs in environmentally and economically acceptable ways. EPRI conducts research on all aspects of electric power production and use, including fuels, generation, delivery, energy management and conservation, environmental effects and energy analysis. The majority of EPRI’s research and development projects are directed toward practical solutions and their applications to problems currently facing the electric utility industry.
FirstEnergy participates in other initiatives with industry R&D consortiums and universities to address technology needs for its various business units. Participation in these consortiums helps the company address research needs in areas such as plant operations and maintenance, major component reliability, environmental controls, advanced energy technologies, and transmission and distribution system infrastructure to improve performance, and develop new technologies for advanced energy and grid applications.


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Executive Officers
Name Age Positions Held During Past Five Years Dates
A. J. Alexander 60  President and Chief Executive Officer (A)(B) *-present
    Chief Executive Officer (F) *-present
    President and Chief Executive Officer (H) 2011-present
    President (C)(D) *-2008
       
L. M. Cavalier 60  Senior Vice President, Human Resources (B) *-present
    Senior Vice President, Human Resources (H) 2011-present
       
M. T. Clark 61  President and Chief Financial Officer (G)(L) 2012-present
    Executive Vice President and Chief Financial Officer (A)(B)(C)(D)(E)(F) 2009-present
    Executive Vice President and Chief Financial Officer (H)(I)(J)(K) 2011-present
    Executive Vice President and Chief Financial Officer (G) 2011
    Executive Vice President, Strategic Planning & Operations (A)(B) 2008-2009
    Senior Vice President, Strategic Planning & Operations (B) *-2008
       
M. J. Dowling 47 Senior Vice President, External Affairs (B)(H) 2011-present
    Vice President, External Affairs (B) 2010-2011
    Vice President, Communications (B) 2008-2010
    Vice President, Governmental Affairs (B) 2007-2008
    Vice President (B) *-2007
       
C. E. Jones 56  Senior Vice President & President, FirstEnergy Utilities (B) 2010-present
    Senior Vice President & President, FirstEnergy Utilities (H) 2011-present
    President (J)(K) 2011-present
    President (C)(D) 2010-present
    Senior Vice President & President, FirstEnergy Utilities (A) 2010-2011
    Senior Vice President, Energy Delivery & Customer Service (B) 2009-2010
    President (E) 2007-2009
    Senior Vice President (B)(C)(D) *-2007
       
J. H. Lash 61  President FE, Generation (B)(H) 2011-present
    Chief Nuclear Officer (F) 2011-present
    President (I) 2011-present
    President and Chief Nuclear Officer (F) 2010-2011
    Senior Vice President and Chief Operating Officer (F) 2007-2010
    Vice President, Beaver Valley (F) *-2007
       
G. R. Leidich 61  Executive Vice President, Integration (A)(B)(H)(M) 2011
    President (G)(M) 2011
    Executive Vice President & President, FirstEnergy Generation (A)(B)(M) 2008-2011
    Senior Vice President, Operations (B) 2007-2008
    President and Chief Nuclear Officer (F) *-2007
       
J. F. Pearson 57  Vice President and Treasurer (A)(B)(C)(D)(E)(F) *-present
    Vice President and Treasurer (G)(H)(I)(J)(K) 2011-present
       
D. R. Schneider 50  President (E) 2009-present
    Senior Vice President, Energy Delivery & Customer Service (B) 2007-2009
    Senior Vice President (C)(D) 2007-2009
    Vice President (B) *-2007
       
L. L. Vespoli 52  Executive Vice President and General Counsel (A)(B)(C)(D)(E)(F) 2008-present
    Executive Vice President and General Counsel (G)(H)(I)(J)(K) 2011-present
    Senior Vice President and General Counsel (A)(B)(C)(D)(E)(F) *-2008
       
H. L. Wagner 59  Vice President, Controller and Chief Accounting Officer (A) *-present
    Vice President and Controller (C)(D)(E)(F) *-present
    Vice President and Controller (G)(I)(J)(K) 2011-present
    Vice President, Controller and Chief Accounting Officer (H) 2011-present
    Vice President, Controller and Chief Accounting Officer (B) 2010-present
    Vice President and Controller (B) *-2010
* Indicates position held at least since January 1, 2007(E) Denotes executive officer of FES(J) Denotes executive officer of MP, PE and WP
(A) Denotes executive officer of FE(F) Denotes executive officer of FENOC(K) Denotes executive officer of TrAIL
(B) Denotes executive officer of FESC(G) Denotes executive officer of AE(L) Position effective January 1, 2012
(C) Denotes executive officer of OE, CEI and TE(H) Denotes executive officer of AESC(M) Retired on December 31, 2011
(D) Denotes executive officer of Met-Ed, Penelec and Penn(I) Denotes executive officer of AGC


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Employees
As of December 31, 2011, FirstEnergy’s subsidiaries had 17,257 employees located in the United States as follows:
 
Total
Employees
 
Bargaining
Unit
Employees
FESC2,975
 293
AESC(1)
3,971
 1,177
OE1,222
 714
CEI897
 608
TE390
 290
Penn204
 153
JCP&L1,413
 1,090
Met-Ed678
 488
Penelec896
 638
ATSI38
 —
FES273
 —
FGCO1,652
 1,061
FENOC2,648
 957
Total17,257
 7,469
(1)
AESC employs substantially all of the former Allegheny personnel who provide services to AE and its subsidiaries, including AE Supply, AGC, MP, PE, WP and TrAIL.
FirstEnergy Web Site
Each of the registrant’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are also made available free of charge on or through FirstEnergy’s internet Web site at www.firstenergycorp.com. These reports are posted on the Web site as soon as reasonably practicable after they are electronically filed with the SEC. Additionally, we routinely post important information on our Web site and recognize our Web site as a channel of distribution to reach public investors and as a means of disclosing material non-public information for complying with disclosure obligations under the SEC's Regulation FD. Information contained on FirstEnergy’s Web site shall not be deemed incorporated into, or to be part of, this report.
In accordance with SEC rules, FirstEnergy will include disclosure of any amendment or waiver to its Code of Ethics or a provision of that Code on its Internet Web site within four business days following the date of any such amendment or waiver.
ITEM 1A.RISK FACTORS
We operate in a business environment that involves significant risks, many of which are beyond our control. Management of each Registrant regularly evaluates the most significant risks of the Registrant’s businesses and reviews those risks with the FirstEnergy Board of Directors or appropriate Committees of the Board. The following risk factors and all other information contained in this report should be considered carefully when evaluating FirstEnergy and our subsidiaries. These risk factors could affect our financial results and cause such results to differ materially from those expressed in any forward-looking statements made by or on behalf of us. Below, we have identified risks we currently consider material. Additional information on risk factors is included in “Item 1. Business” and “Item 7. Management’s Discussion and Analysis of Registrant and Subsidiaries” and in other sections of this Form 10-K that include forward-looking and other statements involving risks and uncertainties that could impact our business and financial results.
Risks Related to Business Operations
Risks Arising from the Reliability of Our Power Plants and Transmission and Distribution Equipment
Operation of generation, transmission and distribution facilities involves risk, including the risk of potential breakdown or failure of equipment or processes due to aging infrastructure, fuel supply or transportation disruptions, accidents, labor disputes or work stoppages by employees, acts of terrorism or sabotage, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions resulting from environmental limitations and governmental interventions, and performance below expected levels. In addition, weather-related incidents and other natural disasters can disrupt generation, transmission and distribution delivery systems. Because our transmission facilities are interconnected with those of third parties, the operation of our facilities could be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties.


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Operation of our power plants below expected capacity could result in lost revenues and increased expenses, including higher operating and maintenance costs, purchased power costs and capital requirements. Unplanned outages of generating units and extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of our business. Unplanned outages typically increase our operation and maintenance expenses and may reduce our revenues as a result of selling fewer MWH or may require us to incur significant costs as a result of operating our higher cost units or obtaining replacement power from third parties in the open market to satisfy our forward power sales obligations. Moreover, if we were unable to perform under contractual obligations, penalties or liability for damages could result.
FES, FGCO and the Ohio Companies are exposed to losses under their applicable sale-leaseback arrangements for generating facilities upon the occurrence of certain contingent events that could render those facilities worthless. Although we believe these types of events are unlikely to occur, FES, FGCO and the Ohio Companies have a maximum exposure to loss under those provisions of approximately $1.4 billion for FES, $606 million for OE and an aggregate of $587 million for TE and CEI as co-lessees.
We remain obligated to provide safe and reliable service to customers within our franchised service territories. Meeting this commitment requires the expenditure of significant capital resources. Failure to provide safe and reliable service and failure to meet regulatory reliability standards due to a number of factors, including, but not limited to, equipment failure and weather, could adversely affect our operating results through reduced revenues and increased capital and operating costs and the imposition of penalties/fines or other adverse regulatory outcomes.
Changes in Commodity Prices Could Adversely Affect Our Profit Margins
We purchase and sell electricity in the competitive wholesale and retail markets. Increases in the costs of fuel for our generation facilities (particularly coal, uranium and natural gas) can affect our profit margins. Changes in the market price of electricity, which are affected by changes in other commodity costs and other factors, may impact our results of operations and financial position by increasing the amount we pay to purchase power to supply POLR and default service obligations in the states we do business. In addition, the global economy could lead to lower international demand for coal, oil and natural gas, which may lower fossil fuel prices and put downward pressure on electricity prices.
Electricity and fuel prices may fluctuate substantially over relatively short periods of time for a variety of reasons, including:
changing weather conditions or seasonality;
changes in electricity usage by our customers;
illiquidity and credit worthiness of participants in wholesale power and other markets;
transmission congestion or transportation constraints, inoperability or inefficiencies;
availability of competitively priced alternative energy sources;
changes in supply and demand for energy commodities;
changes in power production capacity;
outages at our power production facilities or those of our competitors;
changes in production and storage levels of natural gas, lignite, coal, crude oil and refined products;
changes in legislation and regulation; and
natural disasters, wars, acts of sabotage, terrorist acts, embargoes and other catastrophic events.
We Are Exposed to Operational, Price and Credit Risks Associated With Selling and Marketing Products in the Power Markets That We Do Not Always Completely Hedge Against
We purchase and sell power at the wholesale level under market-based tariffs authorized by the FERC, and also enter into agreements to sell available energy and capacity from our generation assets. If we are unable to deliver firm capacity and energy under these agreements, we may be required to pay damages. These damages would generally be based on the difference between the market price to acquire replacement capacity or energy and the contract price of the undelivered capacity or energy. Depending on price volatility in the wholesale energy markets, such damages could be significant. Extreme weather conditions, unplanned power plant outages, transmission disruptions, and other factors could affect our ability to meet our obligations, or cause increases in the market price of replacement capacity and energy.
We attempt to mitigate risks associated with satisfying our contractual power sales arrangements by reserving generation capacity to deliver electricity to satisfy our net firm sales contracts and, when necessary, by purchasing firm transmission service. We also routinely enter into contracts, such as fuel and power purchase and sale commitments, to hedge our exposure to fuel requirements and other energy-related commodities. We may not, however, hedge the entire exposure of our operations from commodity price


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volatility. To the extent we do not hedge against commodity price volatility, our results of operations and financial position could be negatively affected.
The Use of Derivative Contracts by Us to Mitigate Risks Could Result in Financial Losses That May Negatively Impact Our Financial Results
We use a variety of non-derivative and derivative instruments, such as swaps, options, futures and forwards, to manage our commodity and financial market risks. In the absence of actively quoted market prices and pricing information from external sources, the valuation of some of these derivative instruments involves management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of some of these contracts. Also, we could recognize financial losses as a result of volatility in the market values of these contracts or if a counterparty fails to perform.
Financial Derivatives Reforms Could Increase Our Liquidity Needs and Collateral Costs and Impose Additional Regulatory Burdens
In July 2010, federal legislation was enacted to reform financial markets that significantly alter how OTC derivatives are regulated. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank) increased regulatory oversight of OTC derivatives, including (1) requiring standardized OTC derivatives to be traded on registered exchanges regulated by the CFTC, (2) imposing new and potentially higher capital and margin requirements and (3) authorizing the establishment of overall volume and position limits. The law gives the CFTC authority to exempt companies that participate in the swap market as “end users” for hedging purposes which could reduce, but not eliminate, the applicability of these measures to us. These requirements could cause our OTC transactions to be more costly and have an adverse effect on our liquidity due to additional capital requirements. In addition, as these reforms aim to standardize OTC products it could limit the effectiveness of our hedging programs because we would have less ability to tailor OTC derivatives to match the precise risk we are seeking to protect.
We rely on the OTC derivative markets as part of our program to hedge the price risk associated with our power portfolio. The effect on our operations of this legislation will depend in part on whether we are determined to be a swap dealer, a major swap participant or a qualifying end-user through a self-identification process, based on the meaning of those terms to be established in the final rules. If we are determined to be a swap dealer or a major swap participant, we will be required to register with the CFTC and execute most bilateral OTC derivative transactions through an exchange or central clearinghouse. This requirement could require us to commit substantial additional capital to cover increases in collateral costs associated with margin requirements of the major exchanges. We would also be required to comply with increased reporting and record-keeping requirements and follow CFTC-specified business conduct standards, and adhere to position limits in a potentially broad range of energy commodities.
Even if we are not determined to be a swap dealer or a major swap participant, we will be required to comply with additional regulatory obligations under Dodd-Frank, which includes some reporting requirements, clearing some additional transactions that we would otherwise enter into over-the-counter, and having to adhere to position limits. Also, the total burden that the rules could impose on all market participants could cause liquidity in the bilateral OTC swap market to decrease substantially. The new rules could impede our ability to meet our hedge targets in a cost-effective manner. FirstEnergy cannot predict the ultimate outcome that Dodd-Frank will have on its results of operations, cash flows or financial position.
Our Risk Management Policies Relating to Energy and Fuel Prices, and Counterparty Credit, Are by Their Very Nature Risk Related, and We Could Suffer Economic Losses Despite Such Policies
We attempt to mitigate the market risk inherent in our energy, fuel and debt positions. Procedures have been implemented to enhance and monitor compliance with our risk management policies, including validation of transaction and market prices, verification of risk and transaction limits, sensitivity analysis and daily portfolio reporting of various risk measurement metrics. Nonetheless, we cannot economically hedge all of our exposures in these areas and our risk management program may not operate as planned. For example, actual electricity and fuel prices may be significantly different or more volatile than the historical trends and assumptions reflected in our analyses. Also, our power plants might not produce the expected amount of power during a given day or time period due to weather conditions, technical problems or other unanticipated events, which could require us to make energy purchases at higher prices than the prices under our energy supply contracts. In addition, the amount of fuel required for our power plants during a given day or time period could be more than expected, which could require us to buy additional fuel at prices less favorable than the prices under our fuel contracts. As a result, we cannot always predict the impact that our risk management decisions may have on us if actual events lead to greater losses or costs than our risk management positions were intended to hedge.
Our risk management activities, including our power sales agreements with counterparties, rely on projections that depend heavily on judgments and assumptions by management of factors such as future market prices and demand for power and other energy-related commodities. These factors become more difficult to predict and the calculations become less reliable the further into the future these estimates are made. Even when our policies and procedures are followed and decisions are made based on these estimates, results of operations may be diminished if the judgments and assumptions underlying those calculations prove to be inaccurate.
We also face credit risks from parties with whom we contract who could default in their performance, in which cases we could be forced to sell our power into a lower-priced market or make purchases in a higher-priced market than existed at the time of executing


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the contract. Although we have established risk management policies and programs, including credit policies to evaluate counterparty credit risk, there can be no assurance that we will be able to fully meet our obligations, that we will not be required to pay damages for failure to perform or that we will not experience counterparty non-performance or that we will collect for voided contracts. If counterparties to these arrangements fail to perform, we may be forced to enter into alternative hedging arrangements or honor underlying commitments at then-current market prices. In that event, our financial results could be adversely affected.
Nuclear Generation Involves Risks that Include Uncertainties Relating to Health and Safety, Additional Capital Costs, the Adequacy of Insurance Coverage and Nuclear Plant Decommissioning
We are subject to the risks of nuclear generation, including but not limited to the following:
the potential harmful effects on the environment and human health resulting from unplanned radiological releases associated with the operation of our nuclear facilities and the storage, handling and disposal of radioactive materials;
limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with our nuclear operations or those of others in the United States;
uncertainties with respect to contingencies and assessments if insurance coverage is inadequate; and
uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed operation including increases in minimum funding requirements or costs of completion.
The NRC has broad authority under federal law to impose licensing security and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines and/or shut down a unit, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants, including ours. Also, a serious nuclear incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or relicensing of any domestic nuclear unit. See "Potential NRC Regulation in Response to the Incident at Japan's Fukushima Daiichi Nuclear Plant Could Adversely Effect Our Business and Financial Condition" below and Note 16, Commitments, Guarantees and Contingencies - Environmental Matters of the Combined Notes to the Consolidated Financial Statements.
We Have a Significant Percentage of Coal-Fired Generation Capacity Which Exposes us to Risk from Regulations Relating to Coal and Coal Combustion Residuals
Approximately 65% of FirstEnergy's generation fleet capacity is coal-fired. Historically, coal-fired generating plants face greater exposure to the costs of complying with federal, state and local environmental statutes, rules and regulations relating to emissions of SO2 and NOx. In addition, the MATS established coal-fired emission standards for mercury, hydrochloric acid and various metals effective in April 2015, proposed coal combustion residual regulations include an option to reclassify coal ash as a hazardous waste, and there are currently a number of federal, state and international initiatives under consideration to, among other things, require reductions in GHG emissions. These legal requirements and initiatives could require substantial additional costs, extensive mitigation efforts and, in the case of GHG requirements, could raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities. Failure to comply with any such existing or future legal requirements may also result in the assessment of fines and penalties. Significant resources also may be expended to defend against allegations of violations of any such requirements.
Capital Market Performance and Other Changes May Decrease the Value of Pension Fund Assets, Decommissioning and Other Trust Funds Which Then Could Require Significant Additional Funding
Our financial statements reflect the values of the assets held in trust to satisfy our obligations to decommission our nuclear generation facilities and under pension and other postemployment benefit plans. The value of certain of the assets held in these trusts do not have readily determinable market values. Changes in the estimates and assumptions inherent in the value of these assets could affect the value of the trusts. If the value of the assets held by the trusts declines by a material amount, our funding obligation to the trusts could materially increase. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. Forecasting investment earnings and costs to decommission nuclear generating stations, to pay future pensions and other obligations requires significant judgment, and actual results may differ significantly from current estimates. Capital market conditions that generate investment losses or increase the present value of liabilities can negatively impact our results of operations and financial position.
We Could be Subject to Higher Costs and/or Penalties Related to Mandatory Reliability Standards Set by NERC/FERC or Changes in the Rules of Organized Markets and the States in Which We Do Business
As a result of the EPACT, owners, operators, and users of the bulk electric system are subject to mandatory reliability standards promulgated by the NERC and approved by FERC as well as mandatory reliability standards and energy efficiency requirements imposed by each of the states in which we operate. The standards are based on the functions that need to be performed to ensure that the bulk electric system operates reliably. Compliance with modified or new reliability standards may subject us to higher operating costs and/or increased capital expenditures. If we were found not to be in compliance with the mandatory reliability


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standards, we could be subject to sanctions, including substantial monetary penalties.
Reliability standards that were historically subject to voluntary compliance are now mandatory and could subject us to potential civil penalties for violations which could negatively impact our business. The FERC can now impose penalties of $1.0 million per day for failure to comply with these mandatory electric reliability standards.
In addition to direct regulation by the FERC and the states, we are also subject to rules and terms of participation imposed and administered by various RTOs and ISOs. Although these entities are themselves ultimately regulated by the FERC, they can impose rules, restrictions and terms of service that are quasi-regulatory in nature and can have a material adverse impact on our business. For example, the independent market monitors of ISOs and RTOs may impose bidding and scheduling rules to curb the potential exercise of market power and to ensure the market functions. Such actions may materially affect our ability to sell, and the price we receive for, our energy and capacity. In addition, the RTOs may direct our transmission owning affiliates to build new transmission facilities to meet the reliability requirements of the RTO or to provide new or expanded transmission service under the RTO tariffs.
We Rely on Transmission and Distribution Assets That We Do Not Own or Control to Deliver Our Wholesale Electricity. If Transmission is Disrupted, Including Our Own Transmission, or Not Operated Efficiently, or if Capacity is Inadequate, Our Ability to Sell and Deliver Power May Be Hindered
We depend on transmission and distribution facilities owned and operated by utilities and other energy companies to deliver the electricity we sell. If transmission is disrupted (as a result of weather, natural disasters or other reasons) or not operated efficiently by ISOs, in applicable markets, or if capacity is inadequate, our ability to sell and deliver products and satisfy our contractual obligations may be hindered, or we may be unable to sell products on the most favorable terms. In addition, in certain of the markets in which we operate, we may be required to pay for congestion costs if we schedule delivery of power between congestion zones during periods of high demand. If we are unable to hedge or recover for such congestion costs in retail rates, our financial results could be adversely affected.
Demand for electricity within our Utilities’ service areas could stress available transmission capacity requiring alternative routing or curtailing electricity usage that may increase operating costs or reduce revenues with adverse impacts to our results of operations. In addition, as with all utilities, potential concerns over transmission capacity could result in MISO, PJM or the FERC requiring us to upgrade or expand our transmission system, requiring additional capital expenditures.
The FERC requires wholesale electric transmission services to be offered on an open-access, non-discriminatory basis. Although these regulations are designed to encourage competition in wholesale market transactions for electricity, it is possible that fair and equal access to transmission systems will not be available or that sufficient transmission capacity will not be available to transmit electricity as we desire. We cannot predict the timing of industry changes as a result of these initiatives or the adequacy of transmission facilities in specific markets or whether independent system operators in applicable markets will operate the transmission networks, and provide related services, efficiently.
Disruptions in Our Fuel Supplies or Changes in Our Fuel Needs Could Occur, Which Could Adversely Affect Our Ability to Operate Our Generation Facilities or Impact Financial Results

We purchase fuel from a number of suppliers. The lack of availability of fuel at expected prices, or a disruption in the delivery of fuel which exceeds the duration of our on-site fuel inventories, including disruptions as a result of weather, increased transportation costs or other difficulties, labor relations or environmental or other regulations affecting our fuel suppliers, could cause an adverse impact on our ability to operate our facilities, possibly resulting in lower sales and/or higher costs and thereby adversely affect our results of operations. Operation of our coal-fired generation facilities is highly dependent on our ability to procure coal. We have long-term contracts in place for a majority of our coal and coal transportation needs. We may from time to time enter into new, or renegotiate certain of these contracts, but can provide no assurance that such contracts will be negotiated or renegotiated, as the case may be, on satisfactory terms, or at all. In addition, if prices for physical delivery are unfavorable, our financial condition, results of operations and cash flows could be materially adversely affected.

Temperature Variations as well as Weather Conditions or other Natural Disasters Could Have a Negative Impact on Our Results of Operations and Demand Significantly Below or Above Our Forecasts Could Adversely Affect Our Energy Margins
Weather conditions directly influence the demand for electric power. Demand for power generally peaks during the summer and winter months, with market prices also typically peaking at that time. Overall operating results may fluctuate based on weather conditions. In addition, we have historically sold less power, and consequently received less revenue, when weather conditions are milder. Severe weather, such as tornadoes, hurricanes, ice or snowstorms, or droughts or other natural disasters, may cause outages and property damage that may require us to incur additional costs that are generally not insured and that may not be recoverable from customers. The effect of the failure of our facilities to operate as planned under these conditions would be particularly burdensome during a peak demand period.
Customer demand could change as a result of severe weather conditions or other circumstances over which we have no control. We satisfy our electricity supply obligations through a portfolio approach of providing electricity from our generation assets, contractual relationships and market purchases. A significant increase in demand could adversely affect our energy margins if we are required to provide the energy supply to fulfill this increased demand at fixed rates, which we expect would remain below the


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wholesale prices at which we would have to purchase the additional supply if needed or, if we had available capacity, the prices at which we could otherwise sell the additional supply. Accordingly, any significant change in demand could have a material adverse effect on our results of operations and financial position.
We Are Subject to Financial Performance Risks Related to Regional and General Economic Cycles and also Related to Heavy Manufacturing Industries such as Automotive and Steel
Our business follows economic cycles. Economic conditions are a determinant of the demand for electricity and declines in the demand for electricity will reduce our revenues. The regional economy in which our Utilities operate is influenced by conditions in automotive, steel and other heavy industries and as these conditions change, our revenues will be impacted. Additionally, the primary market areas of our Competitive Energy Services segment overlap, to a large degree, with our Utilities' territories and hence its revenues are impacted by the same economic conditions.
Increases in Customer Electric Rates and Economic Uncertainty May Lead to a Greater Amount of Uncollectible Customer Accounts
Our operations are impacted by the economic conditions in our service territories and those conditions could negatively impact the rate of delinquent customer accounts and our collections of accounts receivable which could adversely impact our financial condition, results of operations and cash flows.
We May Recognize Impairments of Recorded Goodwill or of Some of Our Long-Lived Assets, Which Would Result in Write-Offs of the Impaired Amounts
Goodwill could become impaired at one or more of our operating subsidiaries. In addition, one or more of our long-lived assets could become impaired. The actual timing and amounts of any impairments in future years would depend on many factors, including interest rates, sector market performance, our capital structure, market prices for power, results of future rate proceedings, operating and capital expenditure requirements, the value of comparable acquisitions, environmental regulations and other factors.
We Face Certain Human Resource Risks Associated with the Availability of Trained and Qualified Labor to Meet Our Future Staffing Requirements
We must find ways to balance the retention of our aging skilled workforce while recruiting new talent to mitigate losses in critical knowledge and skills due to retirements. Mitigating these risks could require additional financial commitments.
Significant Increases in Our Operation and Maintenance Expenses, Including Our Health Care and Pension Costs, Could Adversely Affect Our Future Earnings and Liquidity
We continually focus on limiting, and reducing where possible, our operation and maintenance expenses. We expect to continue to face increased cost pressures in the areas of health care and pension costs. We have experienced significant health care cost inflation in the last few years, and we expect our cash outlay for health care costs, including prescription drug coverage, to continue to increase despite measures that we have taken and expect to take requiring employees and retirees to bear a higher portion of the costs of their health care benefits. The measurement of our expected future health care and pension obligations and costs is highly dependent on a variety of assumptions, many of which relate to factors beyond our control. These assumptions include investment returns, interest rates, health care cost trends, benefit design changes, salary increases, the demographics of plan participants and regulatory requirements. If actual results differ materially from our assumptions, our costs could be significantly increased.
Our Results May be Adversely Affected by the Volatility in Pension and OPEB Expenses.
Effective in 2011, FirstEnergy elected to change its method of recognizing actuarial gains and losses of its pension and OPEB plans. This change will result in the recognition of net actuarial gains or losses, without deferral, in the fourth quarter of each year and whenever a plan is determined to qualify for a remeasurement, may result in greater volatility in pension and OPEB expenses and may materially impact our results of operations under GAAP. For additional information, see Note 1, Organization, Basis of Presentation and Significant Accounting Policies of the Combined Notes to the Consolidated Financial Statements.
Security Breaches, Including Cyber Security Breaches, and Other Disruptions Could Compromise Critical and Proprietary Information and Expose Us to Liability, Which Would Cause our Business and Reputation to Suffer.
In the ordinary course of our business, we store sensitive data, intellectual property and proprietary information regarding our business, employees, customers, suppliers and business partners in our data centers and on our networks. The secure maintenance of this information is critical to our operations. Despite security measures we have employed with respect to this information, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings and regulatory penalties. It could also disrupt our business operations and damage our reputation, which could adversely affect our business.


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Acts of War or Terrorism Could Negatively Impact Our Business
The possibility that our infrastructure, such as electric generation, transmission and distribution facilities, or that of an interconnected company, could be direct targets of, or indirect casualties of, an act of war or terrorism, could result in disruption of our ability to generate, purchase, transmit or distribute electricity. Any such disruption could result in a decrease in revenues and additional costs to purchase electricity and to replace or repair our assets, which could have a material adverse impact on our results of operations and financial condition.
Capital Improvements and Construction Projects May Not be Completed Within Forecasted Budget, Schedule or Scope Parameters
Our business plan calls for extensive capital investments. We may be exposed to the risk of substantial price increases in the costs of labor and materials used in construction. We engage numerous contractors and enter into a large number of agreements to acquire the necessary materials and/or obtain the required construction-related services. As a result, we are also exposed to the risk that these contractors and other counterparties could breach their obligations to us. Such risk could include our contractors’ inabilities to procure sufficient skilled labor as well as potential work stoppages by that labor force. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices, with resulting delays in those and other projects. Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than these mitigation provisions. This could have negative financial impacts such as incurring losses or delays in completing construction projects.
Changes in Technology May Significantly Affect Our Generation Business by Making Our Generating Facilities Less Competitive
We primarily generate electricity at large central facilities. This method results in economies of scale and lower costs than newer technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells. It is possible that advances in technologies will reduce their costs to levels that are equal to or below that of most central station electricity production, which could have a material adverse effect on our results of operations.
We May Acquire Assets That Could Present Unanticipated Issues for Our Business in the Future, Which Could Adversely Affect Our Ability to Realize Anticipated Benefits of Those Acquisitions
Asset acquisitions involve a number of risks and challenges, including: management attention; integration with existing assets; difficulty in evaluating the requirements associated with the assets prior to acquisition, operating costs, potential environmental and other liabilities, and other factors beyond our control; and an increase in our expenses and working capital requirements. Any of these factors could adversely affect our ability to achieve anticipated levels of cash flows or realize other anticipated benefits from any such asset acquisition.
Ability of Certain FirstEnergy Companies to Meet Their Obligations to or on behalf of Other FirstEnergy Companies or their Affiliates
Certain of the FirstEnergy companies have obligations to other FirstEnergy companies because of transactions involving energy, coal, other commodities, services and hedging transactions. If one FirstEnergy entity failed to perform under any of these arrangements, other FirstEnergy entities could incur losses. Their results of operations, financial position, or liquidity could be adversely affected, resulting in the nondefaulting FirstEnergy entity being unable to meet its obligations to unrelated third parties. Our hedging activities are generally undertaken with a view to overall FirstEnergy exposures. Some FirstEnergy companies may therefore be more or less hedged than if they were to engage in such transactions alone. Also, some companies affiliated with FirstEnergy also provide guarantees to third party creditors on behalf of other FirstEnergy affiliates under transactions of the type described above or under financing transactions. Any failure to perform under such a guarantee by the affiliated FirstEnergy guarantor company or under the underlying transaction by the FirstEnergy company on whose behalf the guarantee was issued could have similar adverse impacts on one or both FirstEnergy companies or their affiliates.
Energy Companies are Subject to Adverse Publicity Which Make Them Vulnerable to Negative Regulatory and Legislative Outcomes

Energy companies, including FirstEnergy's utility subsidiaries, have been the subject of criticism focused on the reliability of their distribution services and the speed with which they are able to respond to power outages, such as those caused by storm damage. Adverse publicity of this nature, or adverse publicity associated with our nuclear and/or coal-fired facilities may cause less favorable legislative and regulatory outcomes.
Our Merger with AE May Not Achieve Its Intended Results.

We entered into the merger agreement with AE with the expectation that the merger would result in various benefits, including, among other things, cost savings and operating efficiencies relating to the regulated business and the unregulated competitive business. Our ability to achieve the anticipated benefits of the merger is subject to a number of uncertainties, including whether the business and information systems of Allegheny are integrated in an efficient and effective manner. Failure to achieve these anticipated benefits could result in increased costs, decreases in the amount of expected revenues generated by us and diversion of management's time and energy and could have an adverse effect on our business, financial results and prospects. See Part II, Item 7, Management's Discussion and Analysis of Registrant and Subsidiaries for additional information.


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Risks Associated With Regulation
Complex and Changing Government Regulations, Including Those Associated With Rates Could Have a Negative Impact on Our Results of Operations
We are subject to comprehensive regulation by various federal, state and local regulatory agencies that significantly influence our operating environment. Changes in, or reinterpretations of, existing laws or regulations, or the imposition of new laws or regulations, could require us to incur additional costs or change the way we conduct our business, and therefore could have an adverse impact on our results of operations.
Our utility subsidiaries currently provide service at rates approved by one or more regulatory commissions. Thus, the rates a utility is allowed to charge may or may not be set to recover its expenses at any given time. Additionally, there may also be a delay between the timing of when costs are incurred and when costs are recovered. For example, we may be unable to timely recover the costs for our energy efficiency investments, expenses and additional capital or lost revenues resulting from the implementation of aggressive energy efficiency programs. While rate regulation is premised on providing an opportunity to earn a reasonable return on invested capital and recovery of operating expenses, there can be no assurance that the applicable regulatory commission will determine that all of our costs have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs in a timely manner.
Regulatory Changes in the Electric Industry, Including a Reversal of, Discontinuance of, or Impediment to the Present Trend Toward Competitive Markets, Could Affect Our Competitive Position and Result in Unrecoverable Costs Adversely Affecting Our Business and Results of Operations
As a result of restructuring initiatives, changes in the electric utility business have occurred, and are continuing to take place throughout the United States, including the states in which we do business. These changes have resulted, and are expected to continue to result, in fundamental alterations in the way utilities conduct their business.
Some states that have deregulated generation service have experienced difficulty in transitioning to market-based pricing. In some instances, state and federal government agencies and other interested parties have made proposals to impose rate cap extensions or otherwise impede market restructuring or even re-regulate areas of these markets that have previously been deregulated. Although we expect wholesale electricity markets to continue to be competitive, proposals to re-regulate our industry may be made, and legislative or other action affecting the electric power restructuring process may cause the process to be delayed, discontinued, restructured or reversed in the states in which we currently, or may in the future, operate. Such delays, discontinuations or reversals of electricity market restructuring in the markets in which we operate could have an adverse impact on our results of operations and financial condition.
The FERC and the U.S. Congress propose changes from time to time in the structure and conduct of the electric utility industry. If the restructuring, deregulation or re-regulation efforts result in decreased margins or unrecoverable costs, our business and results of operations would be adversely affected. We cannot predict the extent or timing of further efforts to restructure, deregulate or re-regulate our business or the industry.
The Prospect of Rising Rates Could Prompt Legislative or Regulatory Action to Restrict or Control Such Rate Increases. This In Turn Could Create Uncertainty Affecting Planning, Costs and Results of Operations and May Adversely Affect the Utilities’ Ability to Recover Their Costs, Maintain Adequate Liquidity and Address Capital Requirements
Increases in utility rates, such as may follow a period of frozen or capped rates, can generate pressure on legislators and regulators to take steps to control those increases. Such efforts can include some form of rate increase moderation, reduction or freeze. The public discourse and debate can increase uncertainty associated with the regulatory process, the level of rates and revenues, and the ability to recover costs. Such uncertainty restricts flexibility and resources, given the need to plan and ensure available financial resources. Such uncertainty also affects the costs of doing business. Such costs could ultimately reduce liquidity, as suppliers tighten payment terms, and increase costs of financing, as lenders demand increased compensation or collateral security to accept such risks.
Our Profitability is Impacted by Our Affiliated Companies’ Continued Authorization to Sell Power at Market-Based Rates
The FERC granted certain subsidiaries authority to sell electricity at market-based rates. These orders also granted them waivers of certain FERC accounting, record-keeping and reporting requirements. The FERC’s orders that grant this market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that these companies can exercise market power in transmission or generation, create barriers to entry or engage in abusive affiliate transactions. As a condition to the orders granting the generating companies market-based rate authority, every three years they are required to file a market power update to show that they continue to meet the FERC’s standards with respect to generation market power and other criteria used to evaluate whether entities qualify for market-based rates.
There Are Uncertainties Relating to Our Participation in RTOs
RTO rules could affect our ability to sell power produced by our generating facilities to users in certain markets due to transmission


34


constraints and attendant congestion costs. The prices in day-ahead and real-time energy markets and RTO capacity markets have been subject to price volatility. Administrative costs imposed by RTOs, including the cost of administering energy markets, have also increased. The rules governing the various regional power markets may also change from time to time, which could affect our costs or revenues. To the degree we incur significant additional fees and increased costs to participate in an RTO, and we are limited with respect to recovery of such costs from retail customers, we may suffer financial harm. In addition, we may be allocated a portion of the cost of transmission facilities built by others due to changes in RTO transmission rate design. Finally, we may be required to expand our transmission system according to decisions made by an RTO rather than our internal planning process. As a member of an RTO, we are subject to certain additional risks, including those associated with the allocation among members of losses caused by unreimbursed defaults of other participants in that RTO’s market and those associated with complaint cases filed against the RTO that may seek refunds of revenues previously earned by its members.
Because it remains unclear which companies will be participating in the various regional power markets, or how RTOs will ultimately develop and operate, or what region they will cover, we cannot fully assess the impact that these power markets or other ongoing RTO developments may have.
Energy Conservation and Energy Price Increases Could Negatively Impact Our Financial Results
A number of regulatory and legislative bodies have introduced requirements and/or incentives to reduce energy consumption. Conservation programs could impact our financial results in different ways. To the extent conservation resulted in reduced energy demand or significantly slowed the growth in demand, the value of our competitive generation and other unregulated business activities could be adversely impacted. We currently have energy efficiency riders in place to recover the cost of these programs either at or near a current recovery timeframe in the states we operate. In New Jersey, we recover the costs for energy efficiency programs through the SBC. Currently only Ohio has provisions for recovery of lost revenues. In our regulated operations, conservation could negatively impact us depending on the regulatory treatment of the associated impacts. Should we be required to invest in conservation measures that result in reduced sales from effective conservation, regulatory lag in adjusting rates for the impact of these measures could have a negative financial impact. We could also be impacted if any future energy price increases result in a decrease in customer usage. Our results could be affected if we are unable to increase our customer’s participation in our energy efficiency programs. We are unable to determine what impact, if any, conservation and increases in energy prices will have on our financial condition or results of operations.
Our Business and Activities are Subject to Extensive Environmental Requirements and Could be Adversely Affected by such Requirements
We plan to retire nine older coal-fired generating plants by September 1, 2012, as a result of a comprehensive review of FirstEnergy's coal-fired generating facilities in light of the MATS rules that were recently finalized and other environmental requirements. We may be forced to shut down other facilities, either temporarily or permanently, if we are unable to comply with certain environmental requirements, or if we make a determination that the expenditures required to comply with such requirements are uneconomical.
The EPA is Conducting NSR Investigations at a Number of Generating Plants that We Currently or Formerly Owned, the Results of Which Could Negatively Impact Our Results of Operations and Financial Condition
We may be subject to risks in connection with changing or conflicting interpretations of existing laws and regulations, including, for example, the applicability of EPA's NSR programs . Under the CAA, modification of our generation facilities in a manner that results in increased emissions could subject our existing facilities to the far more stringent NSR standards applicable to new facilities.
The EPA has taken the view that many companies, including many energy producers, have been modifying emissions sources in violation of NSR standards in connection with work considered by the companies to be routine maintenance. We are currently involved in litigation and EPA investigations concerning alleged violations of the NSR standards at certain of our existing and former generating facilities. We intend to vigorously pursue and defend our position but we are unable to predict their outcomes. If NSR and similar requirements are imposed on our generation facilities, in addition to the possible imposition of fines, compliance could entail significant capital investments in pollution control technology, which could have an adverse impact on our business, results of operations, cash flows and financial condition. For a more complete discussion see Note 16, Commitments, Guarantees and Contingencies - Environmental Matters of the Combined Notes to the Consolidated Financial Statements.
Costs of Compliance with Environmental Laws are Significant, and the Cost of Compliance with Future Environmental Laws, Including Limitations on GHGEmissions, Could Adversely Affect Cash Flow and Profitability

Our operations are subject to extensive federal, state and local environmental statutes, rules and regulations. Compliance with these legal requirements requires us to incur costs for among other things, installation and operation of pollution control equipment, emission monitoring and fees, remediation and permitting at our facilities. These expenditures have been significant in the past and may increase in the future. If the cost of compliance with existing environmental laws and regulations does increase, it could adversely affect our business and results of operations, financial position and cash flows. Moreover, new environmental laws or regulations or changes to existing environmental laws or regulations may materially increase our costs of compliance or accelerate the timing of capital expenditures. Because of the deregulation of generation, we may not directly recover through rates additional costs incurred for such compliance. Our compliance strategy, although reasonably based on available information, may not successfully address future relevant standards and interpretations. If we fail to comply with environmental laws and regulations or


35


new interpretations of longstanding requirements, even if caused by factors beyond our control, that failure could result in the assessment of civil or criminal liability and fines. In addition, any alleged violation of environmental laws and regulations may require us to expend significant resources to defend against any such alleged violations.

There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. Environmental advocacy groups, other organizations and some agencies in the United States and elsewhere are focusing considerable attention on carbon dioxide emissions from power generation facilities and their potential role in climate change. There is a growing consensus in the United States and globally that GHG emissions are a major cause of global warming and that some form of regulation will be forthcoming at the federal level with respect to GHG emissions (including CO2) and such regulation could result in the creation of substantial additional costs in the form of taxes or emission allowances. As a result, it is possible that state and federal regulations will be developed that will impose more stringent limitations on emissions than are currently in effect. Due to the uncertainty of control technologies available to reduce GHG emissions, including CO2, as well as the unknown nature of potential compliance obligations should climate change regulations be enacted, we cannot provide any assurance regarding the potential impacts these future regulations would have on our operations. In addition, any legal obligation that would require us to substantially reduce our emissions could require extensive mitigation efforts and, in the case of carbon dioxide legislation, would raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities. Until specific regulations are issued, the impact that any new environmental regulations, voluntary compliance guidelines, enforcement initiatives, or legislation may have on our results of operations, financial condition or liquidity is not determinable.

FirstEnergy cannot currently estimate the financial impact of certain environmental laws or initiatives including climate change policies, but 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. See Note 16, Commitments, Guarantees and Contingencies - Environmental Matters of the Combined Notes to the Consolidated Financial Statements for a more detailed discussion of the federal, state and international initiatives seeking to reduce emissions of GHG.

We Could be Exposed to Private Rights of Action Seeking Damages Under Various State and Federal Law Theories

Claims have been made against certain energy companies alleging that CO2 emissions from power generating facilities constitute a public nuisance under federal and/or state common law. As a result, private individuals may seek to enforce environmental laws and regulations against us and could allege personal injury or property damages. While FirstEnergy is not a party to this litigation, it, and/or one of its subsidiaries, could be named in actions making similar allegations. An unfavorable ruling in any such case could have an adverse impact on our results of operations and financial condition and could significantly impact our operations.

Our Costs to Comply with Various Recently Adopted EPA Emission Regulations Could be Substantial and Result in Significant Changes to Our Operations

We are required to comply with recently adopted emission regulations. The EPA's CAIR and CSAPR require reductions of NOx and SO2 emissions in two phases, ultimately capping SO2 and NOx emissions in affected states. In July 2011, the EPA finalized the CSAPR (which was stayed in December 2011 pending a decision on various legal challenges) to replace CAIR, which remains in effect until CSAPR becomes effective.

Depending on the outcome of these legal proceedings and how any final rules are ultimately implemented, MP's, FGCO's and AE Supply's future cost of compliance may be substantial and changes to FirstEnergy's operations may result.

Additionally, on December 21, 2011, the EPA finalized the MATS to establish emission standards for, among other things, mercury, hydrochloric acid and various metals for electric generating units. The costs associated with MATS, and other environmental laws, is substantial and led to the Company's recent announcement to retire nine older coal-fired generating units. Depending on how the CSPAR and MATS are ultimately implemented, FirstEnergy's future cost of compliance with such regulations may be substantial and additional changes to FirstEnergy's operations may result. See Note 16, Commitments, Guarantees and Contingencies - Environmental Matters of the Combined Notes to the Consolidated Financial Statements for a more detailed discussion of the above-referenced EPA regulations.

Various Federal and State Water Quality Regulations May Require Us to Make Material Capital Expenditures

The EPA established performance standards under the Clean Water Act which requires the EPA to establish performance standards for reducing impacts on fish and shellfish from cooling water intake structures at certain existing electric generating plants, specifically, impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). In 2011, the EPA proposed new regulations under the Clean Water Act which generally require fish impingement to be reduced to a 12% annual average and calls for studies to be conducted at the majority of our existing generating facilities to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic life. FirstEnergy is studying the cost and effectiveness of various control options to divert fish away from its plants' cooling water intake system. Depending on the results of such studies and the EPA's further rulemaking and any final action taken by the states, the future costs of compliance with these standards may require material capital expenditures. See Note 16, Commitments, Guarantees and Contingencies - Environmental Matters of the Combined Notes to the Consolidated Financial Statements for a more detailed discussion of the various federal and state water


36


quality regulations listed above.

Compliance with any Coal Combustion Residual Regulations Could Have an Adverse Impact on Our Results of Operations and Financial Condition

We are subject to various federal and state hazardous waste regulations. The EPA has requested comments from the states on options for regulating coal combustion residuals, including whether they should be regulated as hazardous or non-hazardous waste.

The EPA asserted that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry and has proposed two options for additional regulation of coal combustion residuals, including the option of regulation as a special waste under the EPA's hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. FirstEnergy's future cost of compliance with any coal combustion residuals regulations that may be issued could be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the EPA or the states. Compliance with those regulations could have an adverse impact on our results of operations and financial condition.
Remediation of Environmental Contamination at Current or Formerly Owned Facilities
We are subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we may have generated regardless of whether the liabilities arose before, during or after the time we owned or operated the facilities. Remediation activities associated with our former MGP operations are one source of such costs. We are currently involved in a number of proceedings relating to sites where other hazardous substances have been deposited and may be subject to additional proceedings in the future. We also have current or previous ownership interests in sites associated with the production of gas and the production and delivery of electricity for which we may be liable for additional costs related to investigation, remediation and monitoring of these sites. Citizen groups or others may bring litigation over environmental issues including claims of various types, such as property damage, personal injury, and citizen challenges to compliance decisions on the enforcement of environmental requirements, such as opacity and other air quality standards, which could subject us to penalties, injunctive relief and the cost of litigation. We cannot predict the amount and timing of all future expenditures (including the potential or magnitude of fines or penalties) related to such environmental matters, although we expect that they could be material.
In some cases, a third party who has acquired assets from us has assumed the liability we may otherwise have for environmental matters related to the transferred property. If the transferee fails to discharge the assumed liability or disputes its responsibility, a regulatory authority or injured person could attempt to hold us responsible, and our remedies against the transferee may be limited by the financial resources of the transferee.
We Are and May Become Subject to Legal Claims Arising from the Presence of Asbestos or Other Regulated Substances at Some of Our Facilities
We have been named as a defendant in pending asbestos litigation involving multiple plaintiffs and multiple defendants. In addition, asbestos and other regulated substances are, and may continue to be, present at our facilities where suitable alternative materials are not available. We believe that any remaining asbestos at our facilities is contained. The continued presence of asbestos and other regulated substances at these facilities, however, could result in additional actions being brought against us.
Availability and Cost of Emission Allowances Could Negatively Impact Our Costs of Operations

Although recent court rulings and current conditions have reduced the immediate risk of a negative impact on our operating costs, the uncertainty around CAA programs and requirements continue to be a major concern. We are still required to maintain, either by allocation or purchase, sufficient emission allowances to support our operations in the ordinary course of operating our power generation facilities. These allowances are used to meet our obligations imposed by various applicable environmental laws. If our operational needs require more than our allocated allowances, we may be forced to purchase such allowances on the open market, which could be costly. If we are unable to maintain sufficient emission allowances to match our operational needs, we may have to curtail our operations so as not to exceed our available emission allowances, or install costly new emissions controls. As we use the emissions allowances that we have purchased on the open market, costs associated with such purchases will be recognized as operating expense. If such allowances are available for purchase, but only at significantly higher prices, the purchase of such allowances could materially increase our costs of operations in the affected markets.
Mandatory Renewable Portfolio Requirements Could Negatively Affect Our Costs
If federal or state legislation mandates the use of renewable and alternative fuel sources, such as wind, solar, biomass and geothermal and such legislation would not also provide for adequate cost recovery, it could result in significant changes in our business, including renewable energy credit purchase costs, purchased power and potentially renewable energy credit costs and capital expenditures. We are unable to predict what impact, if any, these changes may have on our financial condition or results of operations.
The Continuing Availability and Operation of Generating Units is Dependent on Retaining or Renewing the Necessary Licenses, Permits, and Operating Authority from Governmental Entities, Including the NRC


37


We are required to have numerous permits, approvals and certificates from the agencies that regulate our business. We believe the necessary permits, approvals and certificates have been obtained for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from future regulatory activities of any of these agencies and we are not assured that any such permits, approvals or certifications will be renewed.
Potential NRC Regulation in Response to the Incident at Japan's Fukushima Daiichi Nuclear Plant Could Adversely Effect Our Business and Financial Condition

As a result of the NRC's investigation of the incident at the Fukushima Daiichi nuclear plant, potential exists for the NRC to promulgate new or revised requirements with respect to nuclear plants located in the United States, which could necessitate additional expenditures at our nuclear plants. For example, as a follow up to the NRC near-term Task Force's review and analysis of the Fukushima Daiichi accident, in January 2012, the NRC released an updated seismic risk model that plant operators must use in performing the seismic reevaluations recommended by the task force. These reevaluations could result in the required implementation of additional mitigation strategies or modifications. It is also possible that the NRC could suspend or otherwise delay pending nuclear relicensing proceedings, including the Davis-Besse relicensing proceeding. The impact of any such regulatory actions could adversely affect FirstEnergy's financial condition or results of operations.
The Physical Risks Associated with Climate Change May Impact Our Results of Operations and Cash Flows
Physical risks of climate change, such as more frequent or more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, and other related phenomena, could affect some, or all, of our operations. Severe weather or other natural disasters could be destructive, which could result in increased costs, including supply chain costs. An extreme weather event within the Utilities' service areas can also directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment. Finally, climate change could affect the availability of a secure and economical supply of water in some locations, which is essential for continued operation of generating plants.
Future Changes in Accounting Standards May Affect Our Reported Financial Results
The SEC, FASB or other authoritative bodies or governmental entities may issue new pronouncements or new interpretations of existing accounting standards that may require us to change our accounting policies. These changes are beyond our control, can be difficult to predict and could materially impact how we report our financial condition and results of operations. We could be required to apply a new or revised standard retroactively, which could adversely affect our financial position. The SEC announced a work plan to aid in its evaluation of the impact that the use of IFRS by U.S. public companies would have on the U.S. securities market and has identified several potential options to incorporate IFRS in the United States. The SEC expects to announce a more specific course of action in 2012. We continue to monitor the development of the potential implementation of IFRS.
Increases in Taxes and Fees May Adversely Effect Our Results of Operation, Financial Audit and Cash Flow
Due to the revenue needs of the United States and the states and jurisdictions in which we operate, various tax and fee increases may be proposed or considered. We cannot predict whether legislation or regulation will be introduced, the form of any legislation or regulation, whether any such legislation or regulation will be passed by legislatures or regulatory bodies. If enacted, these changes could increase tax costs and could have a negative impact on our results of operations, financial condition and cash flows.
Risks Associated With Financing and Capital Structure
Disruptions in the Capital and Credit Markets May Adversely Affect Our Business, Including the Availability and Cost of Short-Term Funds for Liquidity Requirements, Our Ability to Meet Long-Term Commitments, Our Ability to Hedge Effectively Our Generation Portfolio, and the Competitiveness and Liquidity of Energy Markets; Each Could Adversely Affect Our Results of Operations, Cash Flows and Financial Condition
We rely on the capital markets to meet our financial commitments and short-term liquidity needs if internal funds are not available from our operations. We also use letters of credit provided by various financial institutions to support our hedging operations. Disruptions in the capital and credit markets could adversely affect our ability to draw on our respective credit facilities. Our access to funds under those credit facilities is dependent on the ability of the financial institutions that are parties to the facilities to meet their funding commitments. Those institutions may not be able to meet their funding commitments if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests within a short period of time.
Longer-term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant financial institutions could adversely affect our access to liquidity needed for our business. Any disruption could require us to take measures to conserve cash until the markets stabilize or until alternative credit arrangements or other funding for our business needs can be arranged. Such measures could include deferring capital expenditures, changing hedging strategies to reduce collateral-posting requirements, and reducing or eliminating future dividend payments or other discretionary uses of cash.
The strength and depth of competition in energy markets depends heavily on active participation by multiple counterparties, which


38


could be adversely affected by disruptions in the capital and credit markets. Reduced capital and liquidity and failures of significant institutions that participate in the energy markets could diminish the liquidity and competitiveness of energy markets that are important to our business. Perceived weaknesses in the competitive strength of the energy markets could lead to pressures for greater regulation of those markets or attempts to replace those market structures with other mechanisms for the sale of power, including the requirement of long-term contracts, which could have a material adverse effect on our results of operations and cash flows.
Interest Rates and/or a Credit Rating Downgrade Could Negatively Affect Our Financing Costs, Our Ability to Access Capital and Our Requirement to Post Collateral
We have near-term exposure to interest rates from outstanding indebtedness indexed to variable interest rates, and we have exposure to future interest rates to the extent we seek to raise debt in the capital markets to meet maturing debt obligations and fund construction or other investment opportunities. Past disruptions in capital and credit markets have resulted in higher interest rates on new publicly issued debt securities, increased costs for certain of our variable interest rate debt securities and failed remarketings of variable interest rate tax-exempt debt issued to finance certain of our facilities. Similar future disruptions could increase our financing costs and adversely affect our results of operations. Also, interest rates could change as a result of economic or other events that our risk management processes were not established to address. As a result, we cannot always predict the impact that our risk management decisions may have on us if actual events lead to greater losses or costs than our risk management positions were intended to hedge. Although we employ risk management techniques to hedge against interest rate volatility, significant and sustained increases in market interest rates could materially increase our financing costs and negatively impact our reported results of operations.
We rely on access to bank and capital markets as sources of liquidity for cash requirements not satisfied by cash from operations. A downgrade in our credit ratings from the nationally recognized credit rating agencies, particularly to a level below investment grade, could negatively affect our ability to access the bank and capital markets, especially in a time of uncertainty in either of those markets, and may require us to post cash collateral to support outstanding commodity positions in the wholesale market, as well as available letters of credit and other guarantees. Furthermore, a downgrade could increase the cost of such capital by causing us to incur higher interest rates and fees associated with such capital. A rating downgrade would also increase the fees we pay on our various existing credit facilities, thus increasing the cost of our working capital. A rating downgrade could also impact our ability to grow our businesses by substantially increasing the cost of, or limiting access to, capital. See Note 16, Commitments, Guarantees and Contingencies - Guarantees and Other Assurances of the Combined Notes to the Consolidated Financial Statements for more information associated with a credit ratings downgrade leading to the posting of cash collateral.
The Soundness of Financial Institutions or Counterparties Could Adversely Affect Us
We have exposure to many different domestic and foreign financial institutions and counterparties and we routinely execute transactions with counterparties in connection with our hedging activities, including brokers and dealers, commercial banks, investment banks and other institutions and industry participants. Many of these transactions expose us to credit risk in the event that any of our lenders or counterparties are unable to honor their commitments or otherwise default under a financing agreement. We also deposit cash balances in short-term investments. Our ability to access our cash quickly depends on the soundness of the financial institutions in which those funds reside. Any delay in our ability to access those funds, even for a short period of time, could have a material adverse effect on our results of operations and financial condition.
We Must Rely on Cash from Our Subsidiaries and Any Restrictions on Our Utility Subsidiaries' Ability to Pay Dividends or Make Cash Payments to Us May Adversely Affect Our Financial Condition
We are a holding company and our investments in our subsidiaries are our primary assets. Substantially all of our business is conducted by our subsidiaries. Consequently, our cash flow is dependent on the operating cash flows of our subsidiaries and their ability to upstream cash to the holding company. Our utility subsidiaries are regulated by various state utility commissions that generally possess broad powers to ensure that the needs of utility customers are being met. Those state commissions could attempt to impose restrictions on the ability of our utility subsidiaries to pay dividends or otherwise restrict cash payments to us.
We Cannot Assure Common Shareholders that Future Dividend Payments Will be Made, or if Made, in What Amounts they May be Paid

Our Board of Directors regularly evaluates our common stock dividend policy and determines the dividend rate each quarter. The level of dividends will continue to be influenced by many factors, including, among other things, our earnings, financial condition and cash flows from subsidiaries, as well as general economic and competitive conditions. We cannot assure common shareholders that dividends will be paid in the future, or that, if paid, dividends will be at the same amount or with the same frequency as in the past.
ITEM 1B.UNRESOLVED STAFF COMMENTS
None.


39


ITEM 2.PROPERTIES
The Ohio Companies', Penn's, FGCO’s and NGC’s respective first mortgage indentures constitute direct first liens on substantially all of the respective physical property, subject only to excepted encumbrances, as defined in the first mortgage indentures. See Notes 6, Leases, and 12, Capitalization of the Combined Notes to the Consolidated Financial Statements for information concerning leases and financing encumbrances affecting certain of the Utilities’, FGCO’s and NGC’s properties.
FirstEnergy controls the following generation sources as of January 31, 2012, shown in the table below. Except for the leasehold interests, OVEC participation and wind power arrangements referenced in the footnotes to the table, substantially all FES' competitive generating units are owned by NGC (nuclear) and FGCO (non-nuclear); the regulated generating units are owned by JCP&L and MP.


40


      Competitive  
Plant (Location) Unit Total FES AE Supply Regulated
    Net Demonstrated Capacity (MW)
Super-critical Coal-fired:  
        
Bruce Mansfield (Shippingport, PA) 1
 830
(1) 
830
 —
 —
Bruce Mansfield (Shippingport, PA) 2
 830
(2) 
830
 —
 —
Bruce Mansfield (Shippingport, PA) 3
 830
(3) 
830
 —
 —
Harrison (Haywood, WV) 1-3
 1,984
 —
 1,576
 408
Hatfield's Ferry (Masontown, PA) 1-3
 1,710
 —
 1,710
 —
Pleasants (Willow Island, WV) 1-2
 1,300
 —
 1,200
 100
W. H. Sammis (Stratton, OH) 6-7
 1,200
  
1,200
 —
 —
Fort Martin (Maidsville, WV) 1-2
 1,107
 —
 —
 1,107
Eastlake (Eastlake, OH)(4)
 5
 597
 597
 —
 —
    10,388
 4,287
 4,486
 1,615
Sub-critical and Other Coal-fired:          
W. H. Sammis (Stratton, OH) 1-5
 1,020
  
1,020
 —
 —
Eastlake (Eastlake, OH)(4)
 1-4
 636
 636
 —
 —
Bay Shore (Toledo, OH) 1
 136
 136
    
Bay Shore (Toledo, OH)(4)
 2-4
 495
 495
 —
 —
Armstrong (Adrian, PA)(4)
 1-2
 356
 —
 356
 —
Albright (Albright, WV)(4)
 1-3
 292
 —
 —
 292
Mitchell (Courtney, PA) 3
 288
 —
 288
 —
Lakeshore (Cleveland, OH)(4)
 18
 245
 245
 —
 —
Ashtabula (Ashtabula, OH)(4)
 5
 244
 244
 —
 —
Willow Island (Willow Island, WV)(4)
 1-2
 242
 —
 —
 242
Rivesville (Rivesville, WV)(4)
 5-6
 126
 —
 —
 126
R. Paul Smith (Williamsport, MD)(4)
 3-4
 116
 —
 116
 —
R. E. Burger (Shadyside, OH) 3
 94
 94
 —
 —
OVEC (Cheshire, OH) (Madison, IN) 1-11
 188
(5) 
110
 67
 11
   
 4,478
  
2,980
 827
 671
Nuclear:  
  
  
     
Beaver Valley (Shippingport, PA) 1
 911
  
911
 —
 —
Beaver Valley (Shippingport, PA) 2
 904
(6) 
904
 —
 —
Davis-Besse (Oak Harbor, OH) 1
 908
  
908
 —
 —
Perry (N. Perry Village, OH) 1
 1,268
(7) 
1,268
 —
 —
   
 3,991
  
3,991
 —
 —
Gas/Oil-fired:  
  
  
     
AE Nos. 1, 2, 3, 4 & 5 (Springdale, PA) 1-5
 638
 —
 638
 —
West Lorain (Lorain, OH) 1-6
 545
  
—
 545
 —
AE Nos. 12 & 13 (Chambersburg, PA) 12-13
 88
 —
 88
 —
AE Nos. 8 & 9 (Gans, PA) 8-9
 88
 —
 88
 —
Mitchell (Courtney, PA) 2
 82
 —
 82
 —
Hunlock CT (Hunlock Creek, PA) 1
 45
 —
 45
 —
Buchanan (Oakwood, VA) 1-2
 43
(8) 
—
 43
 —
Other   216
 216
 —
 —
    1,745
 216
 1,529
 —
Pumped-storage and Hydro:  
  
  
     
Bath County (Warm Springs, VA) 1-6
 1,110
(9) 
—
 660
 450
Seneca (Warren, PA) 1-3
 451
  
451
 —
 —
Yard’s Creek (Blairstown Twp., NJ) 1-3
 200
(10) 
—
 —
 200
Lake Lynn (Lake Lynn, PA) 1-4
 52
(11) 
—
 52
  
Other   19
 —
 19
 —
    1,832
 451
 731
 650
Wind Power  
 376
(12) 
376
 —
 —
Total   22,810
 12,301
 7,573
 2,936


41


(1)
Includes FGCO’s leasehold interest of 93.825% (779 MW) and CEI’s leasehold interest of 6.175% (51 MW), which has been assigned to FGCO.
(2)
Includes CEI’s and TE’s leasehold interests of 27.17% (226 MW) and 16.435% (136 MW), respectively, which have been assigned to FGCO.
(3)
Includes CEI’s and TE’s leasehold interests of 23.247% (193 MW) and 18.915% (157 MW), respectively, which have been assigned to FGCO.
(4)
During the first quarter of 2012, FirstEnergy announced that these coal-fired plants will be retired by September 1, 2012, subject to review for reliability impacts by PJM.
(5)
Represents FGCO’s 4.85% and AE's 3.5% entitlement based on their participation in OVEC.
(6)
Includes OE’s leasehold interest of 16.65% (151 MW) from non-affiliates.
(7)
Includes OE’s leasehold interest of 8.11% (103 MW) from non-affiliates.
(8)
Buchanan Energy is a subsidiary of AE Supply. CNX Gas Corporation and Buchanan Energy have equal ownership interests in Buchanan Generation, LLC. AE Supply operates and dispatches 100% of Buchanan Generation, LLC's 86 MWs.
(9)
Represents capacity entitlement through ownership of AGC.
(10)
Represents JCP&L’s 50% ownership interest.
(11)
AE Supply has a license for Lake Lynn through 2024.
(12)
Includes 167 MW from leased facilities and 209 MW under power purchase agreements.
The above generating plants and load centers are connected by a transmission system consisting of elements having various voltage ratings ranging from 23 kV to 500 kV. The Utilities’ overhead and underground transmission lines aggregate 24,305 pole miles.
The Utilities’ electric distribution systems include 254,899 miles of overhead pole line and underground conduit carrying primary, secondary and street lighting circuits. They own substations with a total installed transformer capacity of approximately 140,158,000 kV-amperes.
All of FirstEnergy's generation, transmission and distribution assets operate in PJM.
FirstEnergy’s distribution and transmission systems as of December 31, 2011, consist of the following:
 
Distribution
Lines(1)
 
Transmission
Lines(1)
 
Substation
Transformer
Capacity(2)
   kV Amperes
OE62,238
 461
 7,763,000
Penn13,419
 52
 1,425,000
CEI33,252
 —
 8,938,000
TE17,593
 81
 3,040,000
JCP&L22,800
 2,550
 23,150,000
Met-Ed18,695
 1,406
 10,819,000
Penelec27,131
 2,909
 15,234,000
ATSI(3)
—
 7,524
 23,578,000
WP20,026
 4,419
 14,077,000
MP20,730
 2,625
 15,230,000
PE19,015
 2,126
 11,033,000
TrAIL(4)
—
 152
 5,871,000
Total254,899
 24,305
 140,158,000
(1)
Pole miles
(2)
Top rating of in-service power transformers only. Excludes grounding banks, station power transformers, and generator and customer-owned transformers.
(3)
Represents transmission lines of 69kV and above located in the service areas of OE, Penn, CEI and TE.
(4)
Represents transmission lines at 500kV located in the service areas of MP, PE and WP.
ITEM 3.LEGAL PROCEEDINGS
Reference is made to Note 16, Commitments, Guarantees and Contingencies of the Combined Notes to the Consolidated Financial Statements for a description of certain legal proceedings involving FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec.
ITEM 4.MINE SAFETY DISCLOSURE
Signal Peak Mine Safety
During 2011, FirstEnergy, through its FEV wholly owned subsidiary, held a 50% interest in Global Mining Group, LLC, a joint venture owning Signal Peak, which is a company that constructed and operates the Bull Mountain Mine No. 1 (Mine), an underground coal mine near Roundup Montana. The operation of the Mine is subject to regulation by the MSHA under the Mine Act.


42


On October 18, 2011, FirstEnergy announced that Gunvor Group, Ltd. signed an agreement to purchase a one-third interest in the Signal Peak coal mine in Montana. As a result of the sale, FirstEnergy, through its wholly owned subsidiary, FEV, currently has a 33-1/3% interest in Global Holding, a joint venture that owns Signal Peak.
Information concerning mine safety violations or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act is included in Exhibit 95 to this Annual Report on Form 10-K.
PART II
ITEM 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
The information required by Item 5 regarding FirstEnergy’s market information, including stock exchange listings and quarterly stock market prices, dividends and holders of common stock is included in Item 6.
Information for FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec is not disclosed because they are wholly owned subsidiaries of FirstEnergy and there is no market for their common stock.
Information regarding compensation plans for which shares of FirstEnergy common stock may be issued is incorporated herein by reference to FirstEnergy’s 2012 proxy statement to be filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.
The table below includes information on a monthly basis regarding purchases made by FE of its common stock during the fourth quarter of 2011.
  Period
  October November December Fourth Quarter
Total Number of Shares Purchased(1)
 112,225
 167,674
 712,539
 992,438
Average Price Paid per Share $44.36
 $44.32
 $44.19
 $44.23
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 —
 —
 —
 —
(1)
Share amounts reflect purchases on the open market to satisfy FirstEnergy's obligations to deliver common stock for some or all of the following: 2007 Incentive Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan, Director Compensation, Allegheny Energy, Inc. 1998 Long-Term Incentive Plan, Allegheny Energy, Inc. 2008 Long-Term Incentive Plan, Allegheny Energy, Inc, Non-Employee Director Stock Plan, Allegheny Energy, Inc, Amended and Restated Revised Plan for Deferral of Compensation of Directors, and Stock Investment Plan.
ITEM 6.SELECTED FINANCIAL DATA
For the Years Ended December 31, 2011 
2010(1)
 
2009(1)
 
2008(1)
 
2007(1)
  (In millions, except per share amounts)
Revenues $16,258
 $13,339
 $12,973
 $13,627
 $12,802
Earnings Available to FirstEnergy Corp.(2)
 $885
 $742
 $872
 $623
 $1,489
Earnings per Share of Common Stock:(2)
          
Basic $2.22
 $2.44
 $2.87
 $2.05
 $4.86
Diluted $2.21
 $2.42
 $2.85
 $2.03
 $4.80
Weighted Average Shares Outstanding:          
Basic 399
 304
 304
 304
 306
Diluted 401
 305
 306
 307
 310
Dividends Declared per Share of Common Stock(3)
 $2.20
 $2.20
 $2.20
 $2.20
 $2.05
Total Assets(4)
 $47,326
 $35,531
 $35,054
 $34,206
 $32,394
Capitalization as of December 31:          
Total Equity(5)
 $13,299
 $8,952
 $9,014
 $8,748
 $9,129
Long-Term Debt and Other Long-Term Obligations 15,716
 12,579
 12,008
 9,100
 8,869
Total Capitalization(5)
 $29,015
 $21,531
 $21,022
 $17,848
 $17,998
(1)
Reflects the retrospective change in recognizing pensions and OPEB costs.
(2)
The retrospective change in accounting for pensions and OPEB costs decreased Earnings Available to FirstEnergy Corp and Earnings Per Share (basic; diluted) as follows: 2010 - $42 million ($0.14; $0.15 per share), 2009 - $134 million ($0.44; $0.44 per share) and 2008 - $719


43


million ($2.36; $2.35 per share); and increased Earnings Available to FirstEnergy Corp. and Earnings Per Share (basic; diluted) in 2007 by $180 million ($0.59; $0.58 per share).
(3)
Dividends declared in 2011, 2010, 2009 and 2008 include four quarterly dividends of $0.55 per share. Dividends declared in 2007 include three quarterly payments of $0.50 per share in 2007 and one quarterly payment of $0.55 per share in 2008.
(4)
The retrospective change in accounting for pensions and OPEB costs increased Total Assets as of December 31 as follows: 2010 - $726 million, 2009 - $750 million, 2008 - $685 million and 2007 - $83 million.
(5)
The retrospective change in accounting for pensions and OPEB costs increased Total Equity as of December 31 as follows: 2010 - $439 million, 2009 - $457 million, 2008 - $433 million and 2007 - $122 million.
PRICE RANGE OF COMMON STOCK
The common stock of FirstEnergy Corp. is listed on the New York Stock Exchange under the symbol “FE” and is traded on other registered exchanges.
 2011 2010
 High Low High Low
First Quarter$40.80
 $36.11
 $47.09
 $38.31
Second Quarter$45.80
 $36.50
 $39.96
 $33.57
Third Quarter$46.51
 $38.77
 $39.06
 $34.51
Fourth Quarter$46.10
 $41.55
 $40.12
 $35.00
Yearly$46.51
 $36.11
 $47.09
 $33.57
Prices are from http://finance.yahoo.com.
SHAREHOLDER RETURN
The following graph shows the total cumulative return from a $100 investment on December 31, 2006 in FirstEnergy’s common stock compared with the total cumulative returns of EEI’s Index of Investor-Owned Electric Utility Companies and the S&P 500.
HOLDERS OF COMMON STOCK
There were 115,120 and 114,808 holders of 418,216,437 shares of FirstEnergy’s common stock as of December 31, 2011 and January 31, 2012, respectively. Information regarding retained earnings available for payment of cash dividends is given in Note 12, Capitalization of the Combined Notes to the Consolidated Financial Statements.
CHANGES IN AND CHALLENGESDISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.


44


ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT AND SUBSIDIARIES

Forward-Looking Statements: This Form 10-K 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.
The impact of the regulatory process on the pending matters before FERC in the various states in which we do business including, but not limited to, matters related to rates.
The status of the PATH project in light of PJM's direction to suspend work on the project pending review of its planning process, its re-evaluation of the need for the project and the uncertainty of the timing and amounts of any related capital expenditures.
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.
Financial derivative reforms that could increase our liquidity needs and collateral costs.
The continued ability of FirstEnergy's regulated utilities to collect transition and other costs.
Operation and maintenance costs being higher than anticipated.
Other legislative and regulatory changes, and revised environmental requirements, including possible GHG emission, water intake and coal combustion residual regulations, the potential impacts of any laws, rules or regulations that ultimately replace CAIR, including CSAPR which was stayed by the courts on December 30, 2011, and the effects of the EPA's MATS rules.
The uncertainty of the timing and amounts of the capital expenditures that may arise in connection with litigation, including NSR litigation or potential regulatory initiatives or rulemakings (including that such expenditures could result in our decision to shut down or idle certain generating units).
The uncertainty associated with the company's plan to retire its older unscrubbed regulated and competitive fossil units, including the impact on vendor commitments and PJM's review of the company's plans.
Adverse regulatory or legal decisions and outcomes with respect to our nuclear operations (including, but not limited to the revocation or non-renewal of necessary licenses, approvals or operating permits by the NRC including as a result of the incident at Japan's Fukushima Daiichi Nuclear Plant).
Issues that could result from our continuing investigation and analysis of the indications of cracking in the plant shield building at Davis-Besse.
Adverse legal decisions and outcomes related to Met-Ed's and Penelec's ability to recover certain transmission costs through their transmission service charge riders.
The continuing availability of generating units and changes in their ability to operate at or near full capacity.
Replacement power costs being higher than anticipated or inadequately hedged.
The ability to comply with applicable state and federal reliability standards and energy efficiency mandates.
Changes in customers' demand for power, including but not limited to, changes resulting from the implementation of state and federal energy efficiency mandates.
The ability to accomplish or realize anticipated benefits from strategic goals.
FirstEnergy's ability to improve electric commodity margins and the impact of, among other factors, the increased cost of coal and coal transportation on such margins.
The ability to experience growth in the distribution business.
The changing market conditions that could affect the value of assets held in FirstEnergy's NDTs, pension trusts and other trust funds, and cause FirstEnergy and its subsidiaries to make additional contributions sooner, or in amounts that are larger than currently anticipated.
The impact of changes to material accounting policies.
The ability to access the public securities and other capital and credit markets in accordance with FirstEnergy's financing plan, the cost of such capital and overall condition of the capital and credit markets affecting FirstEnergy and its subsidiaries.
Changes in general economic conditions affecting FirstEnergy and its subsidiaries.
Interest rates and any actions taken by credit rating agencies that could negatively affect FirstEnergy's and its subsidiaries' access to financing or their costs of financings and increase requirements to post additional collateral to support outstanding commodity positions, LOCs and other financial guarantees.
The continuing uncertainty of the national and regional economy and its impact on major industrial and commercial customers of FirstEnergy and its subsidiaries.
Issues concerning the soundness of financial institutions and counterparties with which FirstEnergy and its subsidiaries do business.
Issues arising from the completed merger of FirstEnergy and AE and the ongoing coordination of their combined operations


45


including FirstEnergy's ability to maintain relationships with customers, employees or suppliers, as well as the ability to continue to successfully integrate the businesses and realize cost savings and any other synergies .
The risks and other factors discussed from time to time in FirstEnergy's and its applicable subsidiaries' SEC filings, and other similar factors.

Dividends declared from time to time on FE's common stock during any annual period may in the aggregate vary from the indicated amount due to circumstances considered by FE's Board of Directors at the time of the actual declarations. A security rating is not a recommendation to buy or hold securities and is subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.
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 FirstEnergy's 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. The registrants expressly disclaim any current intention to update, except as required by law, any forward-looking statements contained herein as a result of new information, future events or otherwise.
See Item 1A. Risk Factors for additional information regarding risks that may impact our business, financial condition and results of operations.


46


FIRSTENERGY CORP.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
Earnings available to FirstEnergy Corp. in 2011 were $885 million, or $2.22 per basic share of common stock ($2.21 diluted), compared with $742 million, or $2.44 per basic share of common stock ($2.42 diluted), in 2010 and $872 million, or $2.87 per basic share ($2.85 diluted), in 2009.
Change in Earnings Per Basic Share From Prior Year 2011 2010
     
Earnings Per Basic Share — Prior Year $2.44
 $2.87
Segment operating results(1)-
    
Regulated Distribution 0.05
 0.04
Competitive Energy Services (0.15) 0.10
Regulated Independent Transmission (0.06) 0.12
Non-core asset sales/impairments 0.67
 (0.37)
Generating plant impairments 0.08
 (0.78)
Trust securities impairments 0.02
 0.03
Litigation resolution (0.07) 0.01
Regulatory charges 0.03
 0.45
Mark-to-market adjustments-    
Pension and OPEB actuarial assumptions (0.47) 0.30
All other 0.02
 0.35
Organizational restructuring - 2009 —
 0.14
Debt redemption premiums (0.01) 0.32
Merger-related costs (0.29) (0.16)
Merger Accounting - commodity contracts (0.26) —
Net merger accretion(1)(2)(3)
 0.54
 —
Income tax resolution / retiree drug subsidy (0.03) (0.57)
Settlement of uncertain tax positions (0.05) (0.11)
Depreciation (0.09) (0.02)
Interest expense, net of amounts capitalized (0.14) 0.04
Investment income (0.03) (0.19)
Change in effective tax rate 0.04
 (0.17)
Other (0.02) 0.04
Earnings Per Basic Share $2.22
 $2.44
(1)Excludes amounts that are shown separately
(2)Includes dilutive effect of shares issued in connection with the Allegheny merger
(3)Includes 10 months of Allegheny results in 2011

Merger
On February 25, 2011, the merger between FirstEnergy and AE closed. Pursuant to the terms of the Agreement and Plan of Merger between FirstEnergy, Merger Sub and AE, Merger Sub merged with and into AE with AE continuing as the surviving corporation and a wholly owned subsidiary of FirstEnergy. As part of the merger, AE shareholders received 0.667 of a share of FirstEnergy common stock for each AE share outstanding as of the merger completion date and all outstanding AE equity-based employee compensation awards were converted into FirstEnergy equity-based awards on the same basis.
In connection with the merger, FirstEnergy recorded merger transaction costs of approximately $91 million ($73 million net of tax and $65 million ($47 million net of tax) during 2011 and 2010, respectively. These costs are included in “Other operating expenses” in the Consolidated Statements of Income. In addition, during 2011, $93 million of pre-tax merger integration costs and $36 million of pre-tax charges from merger settlements approved by regulatory agencies were recognized. Charges resulting from merger settlements are not expected to be material in future periods.
FirstEnergy exceeded its 2011 merger benefits target. During 2011, FirstEnergy completed savings initiatives that allowed the


47


company to capture pre-tax annualized merger benefits of approximately $267 million compared to the annual target of $210 million.

Operational Matters

PJM RTO Integration

On June 1, 2011, ATSI successfully integrated into PJM. With this transition, all of FirstEnergy's generation, transmission and distribution facilities are now in PJM.

Transmission Expansion

On May 19, 2011, TrAIL's 500-kV transmission line, spanning more than 150 miles from southwestern Pennsylvania through West Virginia to northern Virginia, was completed and energized.

Nuclear Generation

On April 11, 2011, Beaver Valley Power Station Unit 2 returned to service following a March 7, 2011 shutdown for refueling and maintenance. During the outage, 60 of the 157 fuel assemblies were exchanged, safety inspections were conducted, and numerous maintenance and improvement projects were completed that we believe will result in continued safe and reliable operations.

On June 7, 2011, the Perry Nuclear Power Plant returned to service following a scheduled shutdown for refueling and maintenance which began on April 18, 2011. During the outage, 248 of the 748 fuel assemblies were replaced and safety inspections were successfully conducted. Additionally, numerous preventative maintenance activities and improvement projects were completed that we believe will result in continued safe and reliable operations, including replacement of several control rod blades, rewind of the generator, and routine work on more than 150 valves, pumps and motors.

On October 2, 2011, FENOC completed the controlled shutdown of the Perry Plant due to the loss of a startup transformer. Subsequently, a spare replacement transformer from Davis-Besse Nuclear Power Station was transported to the Perry Plant for modification and installation. The new transformer was installed in 2011.

During 2011, FENOC broke ground for new Emergency Operations Facilities at all three of its nuclear sites. Each of the 12,000 square-foot facilities will house activities related to maintaining public health and safety during the unlikely event of an emergency at the plant and allow for improved coordination between the plant, state and local emergency management agencies.

On October 1, 2011, the Davis-Besse Nuclear Power Station began a scheduled outage for replacement of its reactor vessel head and other scheduled maintenance. On October 10, 2011, following opening of the building for installation of the new reactor head, a sub-surface hairline crack was identified in one of the exterior architectural elements on the shield building. These elements serve as architectural features and do not have structural significance. During investigation of the crack at the shield building opening, concrete samples and electronic testing found similar sub-surface hairline cracks in most of the building's architectural elements. FENOC's investigation also identified other indications of cracking. Included among them were sub-surface hairline cracks in the upper portion of the shield building (above 780 feet of elevation) and in the vicinity of the main steam line penetrations. A team of industry-recognized structural concrete experts and Davis-Besse engineers have determined these conditions do not affect the facility's structural integrity or safety. On February 27, 2012, FENOC sent a root cause evaluation report to the NRC. On December 6, 2011, the Davis-Besse Nuclear Power Station returned to service. The new reactor vessel head features control rod nozzles made of an enhanced material and further promotes safe and reliable operation of the plant.

Coal and Gas Fired Generation

On July 28, 2011, FirstEnergy completed the sale of the Fremont Energy Center to American Municipal Power, Inc. for $510 million based on 685 MW of output. The purchase price can be incrementally increased, not to exceed an additional $16 million, to reflect additional transmission export capacity up to 707 MW.

On October 18, 2011, FirstEnergy sold its Richland (432 MW) and Stryker (18 MW) Peaking Facilities for approximately $80 million. The proceeds from the sale of these non-core assets reduced FirstEnergy's net debt position.

On January 26, 2012, FirstEnergy announced that its unregulated generation subsidiaries will retire six older coal-fired plants located in Ohio, Pennsylvania and Maryland. On February 8, 2012, FirstEnergy announced that MP will retire three older coal-fired plants located in West Virginia. All of these generating plants will be closed by September 1, 2012. The decision to close the plants is the result of a comprehensive review of FirstEnergy's coal-fired generating facilities in light of the MATS rules that were recently finalized and other environmental regulations. These closures are subject to review for reliability impacts by PJM. In addition, MP will make a filing with the WVPSC to provide them with information regarding the retirement of its plants. As a result of this decision, impairment charges associated with these assets were recognized by FirstEnergy, aggregating approximately $334 million ($207 million after-tax) in the fourth quarter of 2011, including approximately $243 million ($152 million after-tax) which is applicable to FES. See Note 11, Impairment of Long-lived Assets, for further information on the retirement of these plants.



48


The total capacity of the competitive plants that will be retired is approximately 2,700 MW and the total capacity of the three regulated plants that will be retired is approximately 660 MW. Recently, these plants served mostly as peaking or intermediate facilities, generating, on average, approximately 10 percent of the electricity produced by FirstEnergy's generation subsidiaries over the past three years.

On February 24, 2012, PJM notified FirstEnergy of its preliminary analysis of the reliability impacts that may result from closure of the older competitive coal-fired generating units. PJM's preliminary analysis indicated that there would be significant reliability concerns that will need to be addressed. FirstEnergy intends to continue to actively engage in discussions with PJM regarding this notification, including the possible continued operation of certain plants.

Signal Peak

On October 18, 2011, FirstEnergy announced that Gunvor Group, Ltd. purchased a one-third interest in Global Holding, a joint venture that owns the Signal Peak coal mine in Montana and the related Global Rail coal transportation operations. The sale strengthened FirstEnergy's balance sheet in the following ways:

Proceeds of $257.5 million reduced FirstEnergy's net debt position;
De-consolidation of Signal Peak resulted in the reduction of indebtedness by $360 million and an increase to equity of $50 million on FirstEnergy's Consolidated Balance Sheet; and
The gain on sale and revaluation of FirstEnergy's remaining ownership stake increased equity by an additional $370 million.

Following the sale, FirstEnergy, through its wholly owned subsidiary, FEV, has a one-third interest in Global Holding. FGCO has a long-term coal supply agreement with Signal Peak for up to 10 million tons per year. FGCO has re-evaluated its coal usage under that agreement and has determined to resell its coal purchased from Signal Peak to an affiliate of Global Holding; provided, however, that such affiliate may require FGCO to repurchase up to 2 million tons annually from the existing underground mines, and, if Signal Peak develops surface mines, it could require FGCO to purchase an additional 2 million tons per year. FirstEnergy remains a 100% guarantor on Signal Peak's and Global Rail's $350 million senior secured credit facility. See Guarantees and Other Assurances below.

FirstEnergy Utilities Respond to Unprecedented Storms

In executing our strategy, we facelate August 2011, FirstEnergy experienced unprecedented damage in its service territory as a numberresult of industryHurricane Irene. Approximately 1.1 million customers were affected by outages in areas served by JCP&L, Met-Ed, Penelec and enterprise risksPE. Approximately 5,000 FirstEnergy employees and challenges, including:

·risks arising from the reliability of our power plants and transmission and distribution equipment;
2,800 contractors, including utility line workers from other utilities, assisted with the restoration work. The cost of the storm totaled approximately $89 million, of which $4 million reduced pre-tax income in 2011 and $85 million was capitalized or deferred for future recovery from customers.

·changes in commodity prices could adversely affect our profit margins;
On October 29, 2011, FirstEnergy was affected by a snowstorm that paralyzed much of the East Coast, including our eastern service areas. Approximately 820,000 customers of JCP&L, Met-Ed, PE, MP, Penelec and WP were affected by the storm that brought down more than 800 poles and approximately 10,000 spans of wire. More than 9,600 employees, contractors and other utilities' crews helped in the restoration. The pre-tax total cost of the storm was approximately $125 million, of which $6 million reduced pre-tax income in 2011 and $119 million was capitalized or deferred for future recovery from customers.

Financial Matters
During 2011, FirstEnergy redeemed or repurchased approximately $520.4 million principal amount of PCRBs, as summarized in the following table. Approximately $28.5 million of FGCO FMBs and $98.9 million of NGC FMBs associated with the PCRBs were returned for cancellation by the associated LOC providers.
SubsidiariesAmount 
 (In millions) 
AE Supply$53.0
(1) 
FGCO$198.2
(2) 
NGC$213.5
(2) 
MP$70.2
(1) 
·
(1)
we
Includes $14.4 million of PCRBs redeemed for which MP and AE Supply are exposed to operational, price and credit risks associated with selling and marketing products in the power markets that we do not always completely hedge against;co-obligors.
(2)
Subject to market conditions, these PCRBs are being held for future remarketing.

On May 4, 2011, AE terminated its $250 million credit facility due to other available funding sources following completion of the merger with FirstEnergy.

·the use of derivative contracts by us to mitigate risks could result in financial losses that may negatively impact our financial results;
On June 17, 2011, FirstEnergy and certain of its subsidiaries entered into two 5-year revolving credit facilities with a total borrowing capacity of $4.5 billion. These facilities consist of a $2 billion revolving credit facility for FirstEnergy and its regulated utility subsidiaries


49


and a $2.5 billion revolving credit facility for FES and AE Supply. Prior separate facilities ($2.75 billion at FirstEnergy, $1 billion at AE Supply, $110 million at MP, $150 million at PE and $200 million at WP) were terminated.

·our risk management policies relating to energy and fuel prices, and counterparty credit, are by their very nature risk related and we could suffer economic losses despite such policies;
During the third quarter of 2011, FirstEnergy received approximately $130 million from assigning a substantially below-market, long-term fossil fuel contract to a third party. As a result, FirstEnergy entered into a new long-term contract with another supplier for replacement fuel based on current market prices. The new contract runs for nine years, which is the remaining term of the assigned contract. The transaction reduced fuel costs during the quarter by approximately $123 million.

·nuclear generation involves risks that include uncertainties relating to health and safety, additional capital costs, the adequacy of insurance coverage and nuclear plant decommissioning;
TrAIL's primary investment, the Trans-Allegheny Interstate Line (a 500-kV transmission project that extends from Southwestern Pennsylvania through West Virginia to Northern Virginia), was completed in May 2011.

·capital market performance and other changes may decrease the value of decommissioning trust fund, pension fund assets and other trust funds which then could require significant additional funding;
On January 26, 2012, FirstEnergy announced a change to its method for accounting for pensions and OPEB effective in 2011 (see Note 1, Organization, Basis of Presentation and Significant Accounting Policies of the Combined Notes to the Consolidated Financial Statements). We also disclosed that we made a $600 million voluntary contribution to our pension plan earlier that month.

·we could be subject to higher costs and/or penalties related to mandatory reliability standards set by NERC/FERC or changes in the rules of organized markets and the states in which we do business;
Regulatory Matters

·we rely on transmission and distribution assets that we do not own or control to deliver our wholesale electricity. If transmission is disrupted, including our own transmission, or not operated efficiently, or if capacity is inadequate, our ability to sell and deliver power may be hindered;

·disruptions in our fuel supplies could occur, which could adversely affect our ability to operate our generation facilities and impact financial results;

·temperature variations as well as weather conditions or other natural disasters could have a negative impact on our results of operations and demand significantly below or above our forecasts could adversely affect our energy margins;

·we are subject to financial performance risks related to regional and general economic cycles and also related to heavy manufacturing industries such as automotive and steel;

·increases in customer electric rates and the impact of the economic downturn may lead to a greater amount of uncollectible customer accounts;

·the goodwill of one or more of our operating subsidiaries may become impaired, which would result in write-offs of the impaired amounts;

60
·we face certain human resource risks associated with the availability of trained and qualified labor to meet our future staffing requirements;

·significant increases in our operation and maintenance expenses, including our health care and pension costs, could adversely affect our future earnings and liquidity;

·our business is subject to the risk that sensitive customer data may be compromised, which could result in an adverse impact to our reputation and/or results of operations;

·acts of war or terrorism could negatively impact our business;

·capital improvements and construction projects may not be completed within forecasted budget, schedule or scope parameters;

·changes in technology may significantly affect our generation business by making our generating facilities less competitive;

·we may acquire assets that could present unanticipated issues for our business in the future, which could adversely affect our ability to realize anticipated benefits of those acquisitions;

·ability of certain FirstEnergy companies to meet their obligations to other FirstEnergy companies;

·ability to obtain the approvals required to complete our merger with Allegheny or, in order to do so, the combined company may be required to comply with material restrictions or conditions;

·if completed, our merger with Allegheny may not achieve its intended results;

·we will be subject to business uncertainties and contractual restrictions while the merger with Allegheny is pending that could adversely affect our financial results;

·failure to complete the merger with Allegheny could negatively impact our stock price and our future business and financial results;

·complex and changing government regulations could have a negative impact on our results of operations;

·regulatory changes in the electric industry, including a reversal, discontinuance or delay of the present trend toward competitive markets, could affect our competitive position and result in unrecoverable costs adversely affecting our business and results of operations;

·the prospect of rising rates could prompt legislative or regulatory action to restrict or control such rate increases; this in turn could create uncertainty affecting planning, costs and results of operations and may adversely affect the utilities’ ability to recover their costs, maintain adequate liquidity and address capital requirements;

·our profitability is impacted by our affiliated companies’ continued authorization to sell power at market-based rates;

·there are uncertainties relating to our participation in regional transmission organizations;

·a significant delay in or challenges to various elements of ATSI’s consolidation into PJM, including but not limited to, the intervention of parties to the regulatory proceedings, could have a negative impact on our results of operations and financial condition;

·energy conservation and energy price increases could negatively impact our financial results;

·the EPA is conducting NSR investigations at a number of our generating plants, the results of which could negatively impact our results of operations and financial condition;

·our business and activities are subject to extensive environmental requirements and could be adversely affected by such requirements;

·
costs of compliance with environmental laws are significant, and the cost of compliance with future environmental laws, including limitations on GHG emissions could adversely affect cash flow and profitability;

61
·the physical risks associated with climate change may impact our results of operations and cash flows;

·remediation of environmental contamination at current or formerly owned facilities;

·availability and cost of emission credits could materially impact our costs of operations;

·mandatory renewable portfolio requirements could negatively affect our costs;

·we are and may become subject to legal claims arising from the presence of asbestos or other regulated substances at some of our facilities;

·the continuing availability and operation of generating units is dependent on retaining the necessary licenses, permits, and operating authority from governmental entities, including the NRC;

·future changes in financial accounting standards may affect our reported financial results;

·increases in taxes and fees;

·interest rates and/or a credit rating downgrade could negatively affect our financing costs, our ability to access capital and our requirement to post collateral;

·we must rely on cash from our subsidiaries and any restrictions on our utility subsidiaries’ ability to pay dividends or make cash payments to us may adversely affect our financial condition;

·we cannot assure common shareholders that future dividend payments will be made, or if made, in what amounts they may be paid;

·disruptions in the capital and credit markets may adversely affect our business, including the availability and cost of short-term funds for liquidity requirements, our ability to meet long-term commitments, our ability to effectively hedge our generation portfolio, and the competitiveness and liquidity of energy markets; each could adversely affect our results of operations, cash flows and financial condition; and

·questions regarding the soundness of financial institutions or counterparties could adversely affect us.

RESULTS OF OPERATIONSMet-Ed and Penelec Transition to Competitive Markets

The financial results discussed below include revenuesPennsylvania Companies began the move to competitive markets with the expiration of the rate caps on Met-Ed's and expensesPenelec's retail generation rates on December 31, 2010. Beginning in 2011, Met-Ed and Penelec obtained their power supply from transactions among our business segments. the competitive wholesale market and fully recover their generation costs through retail rates. The Ohio Companies, Penn, WP and JCP&L previously transitioned to competitive generation markets.

Marginal transmission loss recovery

On March 3, 2010, the PPUC issued an order denying Met-Ed and Penelec the ability to recover marginal transmission losses through the transmission service charge riders in their respective tariffs which applies to the periods including June 1, 2008 through December 31, 2010. Subsequently, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania (Commonwealth Court) appealing the PPUC's order. On June 14, 2011, the Commonwealth Court affirmed the PPUC's decision that marginal transmission losses are not recoverable as transmission costs. On July 13, 2011, Met-Ed and Penelec filed a federal complaint with the United States District Court for the Eastern District of Pennsylvania and on the following day, filed a Petition for Allowance of Appeal to the Pennsylvania Supreme Court. Met-Ed and Penelec believe the Commonwealth Court's decision contradicts federal law and is inconsistent with prior PPUC and court decisions and therefore expect to fully recover the related regulatory assets ($189 million for Met-Ed and $65 million for Penelec). In January 2011 and continuing for 29 months, pursuant to a related PPUC order, Met-Ed and Penelec began crediting customers for the amounts at issue pending the outcome of court appeals.

Ohio Energy Efficiency and Peak Demand Reduction Portfolio Plan

On March 23, 2011, the PUCO approved the three-year Energy Efficiency and Demand Reduction portfolio plan for the Ohio Companies. The Ohio Companies' plan was developed to comply with the Energy Efficiency mandate in Ohio's SB 221, passed in 2008. This law requires that utilities in Ohio reduce energy usage by 22.2 percent by 2025 and peak demand by 7.75 percent by 2018, develop a portfolio plan, and meet annual benchmarks to measure progress.

NYSEG Ruling

On July 11, 2011, FirstEnergy was found to be a potentially responsible party under CERCLA indirectly liable for a portion of past and future clean-up costs at certain legacy MGP sites in New York. As a result, FirstEnergy recognized additional expense of $29 million during the second quarter of 2011.

West Virginia Fuel, Purchased Power Cost Decision

On December 30, 2011, MP and PE announced that the WVPSC issued an order regarding the companies' adjustment of fuel and purchased power costs. The WVPSC's order approved a settlement agreement between the companies, the Consumer Advocate Division, the Staff of the WVPSC and the West Virginia Energy Users Group. In the approved settlement, parties have agreed that the companies will recover an additional $19.6 million in 2012, an approximate 1.7 percent increase, primarily reflecting rising coal prices over the past two years, with certain additional amounts to be recovered over time with a carrying charge.
FIRSTENERGY’S BUSINESS
With the completion of transitionthe AE merger in the first quarter of 2011, FirstEnergy reorganized its management structure, which resulted in changes to a fully competitiveits operating segments to be consistent with the manner in which management views the business. The new structure supports the combined company's primary operations - distribution, transmission, generation marketand the marketing and sale of its products. The external segment reporting is consistent with the internal financial reporting used by FirstEnergy's chief executive


50


officer (its chief operating decision maker) to regularly assess the performance of the business and allocate resources. FirstEnergy now has three reportable operating segments - Regulated Distribution, Regulated Independent Transmission and Competitive Energy Services.
Prior to the change in Ohio in 2009, the former Ohio Transitional Generation Services segmentcomposition of business segments, FirstEnergy's business was combined with thecomprised of two reportable operating segments. The Energy Delivery Services segment consistent with how management viewswas comprised of FirstEnergy's then eight existing utility operating companies that transmit and distribute electricity to customers and purchase power to serve their POLR and default service requirements. The Competitive Energy Services segment was comprised of FES, which supplies electric power to end-use customers through retail and wholesale arrangements. The “Other/Corporate” amounts consisted of corporate items and other businesses that were below the business.quantifiable threshold for separate disclosure. Disclosures for FirstEnergy’sFirstEnergy's operating segments for 2008 and 20072010 have been reclassified to conform to the 2009revised presentation. A reconciliation
The changes in FirstEnergy's reportable segments during 2011 consisted primarily of segment financial results is providedthe following:
Energy Delivery Services was renamed Regulated Distribution and the operations of MP, PE and WP, which were acquired as part of the merger with AE, and certain regulatory asset recovery mechanisms formerly included in Note 16 to the consolidated financial statements. Earnings available to FirstEnergy Corp. by major business“Other/Corporate” segment, were placed into this segment.
A new Regulated Independent Transmission segment was created consisting of ATSI, and the operations of TrAIL and FirstEnergy's interest in PATH; TrAIL and PATH were acquired as follows:part of the merger with AE. The transmission assets and operations of JCP&L, Met-Ed, Penelec, MP, PE and WP remained within the Regulated Distribution segment.

       Increase (Decrease) 
 2009 2008 2007 2009 vs 2008 2008 vs 2007 
 (In millions, except per share amounts) 
Earnings Available to FirstEnergy Corp.          
By Business Segment:          
Energy delivery services $435  $916  $965  $(481) $(49)
Competitive energy services  517   472   495   45   (23)
Other and reconciling adjustments*  54   (46)  (151)  100   105 
Total $1,006  $1,342  $1,309  $(336) $33 
                     
Basic Earnings Per Share: $3.31  $4.41  $4.27  $(1.10) $0.14 
Diluted Earnings Per Share: $3.29  $4.38  $4.22  $(1.09) $0.16 
                     
* Consists primarily of interest expense related to holding company debt, corporate support services revenues and expenses, and elimination of intersegment transactions.
 
62
SummaryAE Supply, an operator of Resultsgeneration facilities that was acquired as part of Operations – 2009 Comparedthe merger with 2008

Financial results for our major business segments in 2009 and 2008 were as follows:

  Energy  Competitive  Other and    
  Delivery  Energy  Reconciling  FirstEnergy 
2009 Financial Results Services  Services  Adjustments  Consolidated 
  (In millions) 
Revenues:            
External            
Electric $10,585  $1,447  $-  $12,032 
Other  559   441   (82)  918 
Internal*  -   2,843   (2,826)  17 
Total Revenues  11,144   4,731   (2,908)  12,967 
                 
Expenses:                
Fuel  -   1,153   -   1,153 
Purchased power  6,560   996   (2,826)  4,730 
Other operating expenses  1,424   1,357   (84)  2,697 
Provision for depreciation  445   270   21   736 
Amortization of regulatory assets  1,155   -   -   1,155 
Deferral of new regulatory assets  (136)  -   -   (136)
General taxes  641   108   4   753 
Total Expenses  10,089   3,884   (2,885)  11,088 
                 
Operating Income  1,055   847   (23)  1,879 
Other Income (Expense):                
Investment income  139   121   (56)  204 
Interest expense  (472)  (166)  (340)  (978)
Capitalized interest  3   60   67   130 
Total Other Income (Expense)  (330)  15   (329)  (644)
                 
Income Before Income Taxes  725   862   (352)  1,235 
Income taxes  290   345   (390)  245 
Net Income  435   517   38   990 
Less: Noncontrolling interest income (loss)  -   -   (16)  (16)
Earnings available to FirstEnergy Corp. $435  $517  $54  $1,006 

*Consistent with the accounting for the effects of certain types of regulation, internal revenues do not fully eliminate representing sales of RECs by FES to the Ohio Companies.
63
2008 Financial Results 
Energy
Delivery
Services
  
Competitive
Energy
Services
  
Other and
Reconciling
Adjustments
  
FirstEnergy
Consolidated
 
  (In millions) 
Revenues:            
External            
Electric $11,360  $1,333  $-  $12,693 
Other  708   238   (12)  934 
Internal  -   2,968   (2,968)  - 
Total Revenues  12,068   4,539   (2,980)  13,627 
                 
Expenses:                
Fuel  2   1,338   -   1,340 
Purchased power  6,480   779   (2,968)  4,291 
Other operating expenses  2,022   1,142   (119)  3,045 
Provision for depreciation  417   243   17   677 
Amortization of regulatory assets, net  1,053   -   -   1,053 
Deferral of new regulatory assets  (316)  -   -   (316)
General taxes  646   109   23   778 
Total Expenses  10,304   3,611   (3,047)  10,868 
                 
Operating Income  1,764   928   67   2,759 
Other Income (Expense):                
Investment income  171   (34)  (78)  59 
Interest expense  (411)  (152)  (191)  (754)
Capitalized interest  3   44   5   52 
Total Other Expense  (237)  (142)  (264)  (643)
                 
Income Before Income Taxes  1,527   786   (197)  2,116 
Income taxes  611   314   (148)  777 
Net Income  916   472   (49)  1,339 
Less: Noncontrolling interest income (loss)  -   -   (3)  (3)
Earnings available to FirstEnergy Corp. $916  $472  $(46) $1,342 
                 
Changes Between 2009 and                
2008 Financial Results Increase (Decrease)                
                 
Revenues:                
External                
Electric $(775) $114  $-  $(661)
Other  (149)  203   (70)  (16)
Internal*  -   (125)  142   17 
Total Revenues  (924)  192   72   (660)
                 
Expenses:                
Fuel  (2)  (185)  -   (187)
Purchased power  80   217   142   439 
Other operating expenses  (598)  215   35   (348)
Provision for depreciation  28   27   4   59 
Amortization of regulatory assets  102   -   -   102 
Deferral of new regulatory assets  180   -   -   180 
General taxes  (5)  (1)  (19)  (25)
Total Expenses  (215)  273   162   220 
                 
Operating Income  (709)  (81)  (90)  (880)
Other Income (Expense):                
Investment income  (32)  155   22   145 
Interest expense  (61)  (14)  (149)  (224)
Capitalized interest  -   16   62   78 
Total Other Income (Expense)  (93)  157   (65)  (1)
                 
Income Before Income Taxes  (802)  76   (155)  (881)
Income taxes  (321)  31   (242)  (532)
Net Income  (481)  45   87   (349)
Less: Noncontrolling interest income (loss)  -   -   (13)  (13)
Earnings available to FirstEnergy Corp. $(481) $45  $100  $(336)

*Consistent with the accounting for the effects of certain types of regulation, internal revenues do not fully eliminate representing sales of RECs by FES to the Ohio Companies.
64
Energy Delivery Services – 2009 Compared to 2008

Net income decreased $481 million to $435 million in 2009 compared to $916 million in 2008, primarily due to lower revenues, increased purchased power costs and decreased deferrals of new regulatory assets, partially offset by lower other operating expenses.AE, was placed into the Competitive Energy Services segment with FES.

Revenues –Regulated Distribution

The decrease in total revenues resulted from the following sources:

Revenues by Type of Service 2009  2008  
Increase
(Decrease)
 
  (In millions) 
Distribution services
 $3,420  $3,882  $(462)
Generation sales:
            
Retail
  5,760   5,768   (8)
Wholesale
  752   962   (210)
Total generation sales
  6,512   6,730   (218)
Transmission
  1,023   1,268   (245)
Other
  189   188   1 
Total Revenues
 $11,144  $12,068  $(924)

The decreases indistributes electricity through our ten utility distribution deliveries by customer class are summarized in the following table:

Electric Distribution KWH Deliveries
Residential
(3.3)
%
Commercial
(4.4)
%
Industrial
(14.7)
%
Total Distribution KWH Deliveries
(7.3)
%

The lower revenues from distribution services were driven primarily by the reductions in sales volume associated with milder weathercompanies, serving approximately 6 million customers within 67,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and economic conditions. The decrease in residential deliveries reflected reduced weather-related usage compared to 2008, as cooling degree daysNew York, and heating degree days decreased by 17%purchases power for its POLR, SOS and 1%, respectively. The decreases in distribution deliveries to commercial and industrial customers were primarily due to economic conditions in FirstEnergy's service territory. In the industrial sector, KWH deliveries declined to major automotive customers by 20.2% and to steel customers by 36.2%. Reduced revenues from transition charges for OE and TE that ceased with the full recovery of related costs effective January 1, 2009 and the transition rate reduction for CEI effective June 1, 2009, were offset by PUCO-approved distribution rate increases (see Regulatory Matters – Ohio).

The following table summarizes the price and volume factors contributing to the $218 million decrease in generation revenues in 2009 compared to 2008:

  Increase 
Sources of Change in Generation Revenues (Decrease) 
  (In millions) 
Retail:    
Effect of 10.5% decrease in sales volumes $(603)
Change in prices  595 
   (8)
Wholesale:    
Effect of 14.9% decrease in sales volumes  (143)
Change in prices  (67)
   (210)
Net Decrease in Generation Revenues $(218)

The decrease in retail generation sales volumes from 2008 was primarily due to the weakened economic conditions and milder weather described above. Retail generation prices increased for JCP&L and Penn during 2009 as a result of their power procurement processes. For the Ohio Companies, average prices increased primarily due to the higher fuel cost recovery riders that were effective from January through May 2009. In addition, effective June 1, 2009, the Ohio Companies’ transmission tariff ended and the recovery of transmission costs is included in the generation rate established under the CBP.

65
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.

Transmission revenues decreased $245 million primarily due to the termination of the Ohio Companies’ current transmission tariff and lower MISO and PJM transmission revenues, partially offset by higher transmission rates for Met-Ed and Penelec resulting from the annual updates to their TSC riders (see Regulatory Matters). The difference between transmission revenues accrued and transmission costs incurred are deferred, resulting in no material effect on current period earnings.

Expenses –

Total expenses increased by $215 million due to the following:

·
Purchased power costs were $80 million higher in 2009 due to higher unit costs, partially offset by an increase in volumes combined with higher NUG cost deferrals. The increased purchased power costs from non-affiliates was due primarily to increased volumes for the Ohio Companies as a result of their CBP, partially offset by lower volumes for Met-Ed and Penelec due to the termination of a third-party supply contract in December 2008 and for JCP&L due to the termination of a NUG purchase contract in October 2008. Decreased purchased power costs from FES were principally due to lower volumes for the Ohio Companies following their CBP, partially offset by increased volumes for Met-Ed and Penelec under their fixed-price partial requirements PSA with FES. Higher unit costs from FES, which included a component for transmission under the Ohio Companies’ CBP, partially offset the decreased volumes.
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 $58 
Change due to increased volumes  312 
   370 
Purchases from FES:    
Change due to increased unit costs  583 
Change due to decreased volumes  (725)
   (142)
     
Increase in NUG costs deferred  (148)
Net Increase in Purchased Power Costs $80 

·Transmission expenses were lower by $481 million in 2009, reflecting the change in the transmission tariff under the Ohio Companies' CBP, reduced transmission volumes and lower congestion costs.

·Intersegment cost reimbursements related to the Ohio Companies’ nuclear generation leasehold interests increased by $114 million in 2009.  Prior to 2009, a portion of OE’s and TE’s leasehold costs were recovered through customer transition charges.  Effective January 1, 2009, these leasehold costs are reimbursed from the competitive energy services segment.

·Labor and employee benefit expenses decreased by $39 million reflecting changes to Energy Delivery's organizational and compensation structure and increased resources dedicated to capital projects, partially offset by higher pension expenses resulting from reduced pension plan asset values at the end of 2008.

·Storm-related costs were $16 million lower in 2009 compared to the prior year.

·An increase in other operating expenses of $40 million resulted from the recognition of economic development and energy efficiency obligations in accordance with the PUCO-approved ESP.

·Uncollectible expenses were higher by $12 million in 2009 principally due to increased bankruptcies.

·A $102 million increase in the amortization of regulatory assets was due primarily to the ESP-related impairment of CEI’s regulatory assets ($216 million) and MISO/PJM transmission cost amortization in 2009, partially offset by the cessation of transition cost amortization for OE and TE.

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·A $180 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, partially offset by the PUCO-approved deferral of purchased power costs for CEI.
·Depreciation expense increased $28 million due to property additions since 2008.

·General taxes decreased $5 million due primarily to lower revenue-related taxes in 2009.

Other Expense –

Other expense increased $93 million in 2009 compared to 2008. Lower investment income of $32 million resulted primarily from repaid notes receivable from affiliates. Higher interest expense (net of capitalized interest) of $61 million resulted from a net increase in debt of $1.8 billion by the Utilities and ATSI during 2009.

Competitive Energy Services – 2009 Compared to 2008

Net income increased to $517 million in 2009 compared to $472 million in the same period of 2008. The increase in net income includes FGCO's gain from the sale of a 9% participation interest in OVEC, increased sales margins, and an increase in investment income, offset by a mark-to-market adjustment relating to purchased power contracts for delivery in 2010 and 2011.

Revenues –

Total revenues increased $192 million in 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:

Revenues by Type of Service 2009  2008  
Increase
(Decrease)
 
  (In millions) 
Non-Affiliated Generation Sales:
         
Retail
 $778  $615  $163 
Wholesale
  669   718   (49)
Total Non-Affiliated Generation Sales
  1,447   1,333   114 
Affiliated Generation Sales
  2,843   2,968   (125)
Transmission
  73   150   (77)
Sale of OVEC participation interest
  252   -   252 
Other
  116   88   28 
Total Revenues
 $4,731  $4,539  $192 

The increase in non-affiliated retail revenues of $163 million resulted from 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, higher unit prices and the inclusion of the transmission related component in retail rates previously reported as transmission revenues. The increase in PJM retail revenue resulted from the acquisition of new customers, higher sales volumes and unit prices. The acquisition of new customers in MISO is primarily due to new government aggregation contracts with 60 area communities in Ohio that will provide discounted generation prices to approximately 580,000 residential and small commercial customers. Lower non-affiliated wholesale revenues of $49 million resulted from decreased sales volumes in PJM partially offset by increased capacity prices, increased sales volumes in MISO, and favorable settlements on hedged transactions.

The lower affiliated company wholesale generation revenues of $125 million were due to lower sales volumes to the Ohio Companies combined with lower unit prices to the Pennsylvania companies, partially offset by higher unit prices to the Ohio Companies and increased sales volumes to the Pennsylvania Companies. The lower sales volumes and higher unit prices to the Ohio Companies reflected the results of the 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 2009 compared to 2008. Additionally, while unit prices for eachOhio, Pennsylvania, New Jersey and Maryland. This segment also includes the transmission operations of JCP&L, Met-Ed, Penelec, WP, MP and PE and the Pennsylvania Companies did not change,regulated electric generation facilities in West Virginia and New Jersey which MP and JCP&L, respectively, own or contractually control. Its results reflect the mixcommodity costs of sales amongsecuring electric generation and the companies caused the overall price to decline.deferral and amortization of certain fuel costs.

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The following tables summarize the price and volume factors contributing to changes in revenues from generation sales:service areas of our regulated distribution utilities are summarized below:

  Increase 
Source of Change in Non-Affiliated Generation Revenues
 
(Decrease)
 
  (In millions) 
Retail:    
Effect of 8.6 % increase in sales volumes $
53
 
Change in prices  
110
 
   
163
 
Wholesale:    
Effect of 13.9 % decrease in sales volumes  
(100
)
Change in prices  
51
 
   
(49
)
Net Increase in Non-Affiliated Generation Revenues 
$
114
 


  Increase 
Source of Change in Affiliated Generation Revenues
 
(Decrease)
 
  (In millions) 
Ohio Companies:    
Effect of 36.3 % decrease in sales volumes $
(837
)
Change in prices  
645
 
   
(192
)
Pennsylvania Companies:    
Effect of 14.7 % increase in sales volumes  
97
 
Change in prices  
(30
)
   
67
 
Net Decrease in Affiliated Generation Revenues 
$
(125
)

Transmission revenues decreased $77 million due primarily to reduced loads following the expiration of the government aggregation programs in Ohio at the end of 2008 and to the inclusion of the transmission-related component in the retail rates in mid-2009. In 2009 FGCO sold 9% of its participation interest in OVEC resulting in a $252 million ($158 million, after tax) gain. Other revenue increased $28 million primarily due to income associated with NGC's acquisition of equity interests in the Perry and Beaver Valley Unit 2 leases.

Expenses - -

Total expenses increased $273 million in 2009 due to the following factors:

·Fossil Fuel costs decreased $198 million due primarily to lower generation volumes ($307 million) partially offset by higher unit prices ($109 million). Nuclear Fuel costs increased $13 million as higher unit prices ($26 million) were partially offset by lower generation ($13 million).

Company ·Area ServedPurchased power costs increased $217 million due to a mark-to-market adjustment ($205 million) relating to purchased power contracts for delivery in 2010 and 2011 and higher unit prices ($33 million) that resulted primarily from higher capacity costs, partially offset by lower volumes purchased ($21 million) due to FGCO's reduced participation interest in OVEC.

 ·Fossil operating costs decreased $24 million due primarily to a reduction in contractor, material and labor costs and increased resources dedicated to capital projects, partially offset by higher employee benefits.Customers Served

OE ·Nuclear operating costs increased $45 million due to an additional refueling outage during the 2009 periodCentral and higher employee benefits, partially offset by lower labor costs.Northeastern Ohio

 ·1,032,000Transmission expense increased $121 million due to transmission services charges related to the load serving entity obligations in MISO, increased net congestion and higher loss expenses in MISO and PJM.

Penn ·Western PennsylvaniaOther expense increased $72 million due primarily to increased intersegment billings for leasehold costs from the Ohio Companies and higher pension costs.

 ·161,000Depreciation expense increased $27 million due to NGC's increased ownership interest in Beaver Valley Unit 2
CEINortheastern Ohio747,000
TENorthwestern Ohio309,000
JCP&LNorthern, Western and Perry.East Central New Jersey1,099,000

68
Other Income (Expense) –

Total other income in 2009 was $15 million compared to total other expense in 2008 of $142 million, resulting primarily from a $155 million increase from gains on the sale of nuclear decommissioning trust investments. During 2009, the majority of the nuclear decommissioning trust holdings were converted to more closely align with the liability being funded.

Other – 2009 Compared to 2008

Our financial results from other operating segments and reconciling items resulted in a $100 million increase in net income in 2009 compared to 2008. The increase resulted primarily from $200 million of favorable tax settlements, offset by debt redemption costs of $90 million and by the absence of the gain from the sale of telecommunication assets ($19 million, net of taxes) in 2008.

69

Summary of Results of Operations – 2008 Compared with 2007

Financial results for our major business segments in 2007 were as follows:

2007 Financial Results 
Energy Delivery
Services
  
Competitive Energy
Services
  
Other and Reconciling
Adjustments
  
FirstEnergy
Consolidated
 
  (In millions) 
Revenues:            
External            
Electric $10,628  $1,316  $-  $11,944 
Other  694   152   12   858 
Internal  -   2,901   (2,901)  - 
Total Revenues  11,322   4,369   (2,889)  12,802 
                 
Expenses:                
Fuel  5   1,173   -   1,178 
Purchased power  5,973   764   (2,901)  3,836 
Other operating expenses  2,005   1,160   (82)  3,083 
Provision for depreciation  404   204   30   638 
Amortization of regulatory assets  1,019   -   -   1,019 
Deferral of new regulatory assets  (524)  -   -   (524)
General taxes  627   107   20   754 
Total Expenses  9,509   3,408   (2,933)  9,984 
                 
Operating Income  1,813   961   44   2,818 
Other Income (Expense):                
Investment income  241   16   (137)  120 
Interest expense  (457)  (172)  (146)  (775)
Capitalized interest  11   20   1   32 
Total Other Expense  (205)  (136)  (282)  (623)
                 
Income Before Income Taxes  1,608   825   (238)  2,195 
Income taxes  643   330   (90)  883 
Net Income  965   495   (148)  1,312 
Less: Noncontrolling interest income  -   -   3   3 
Earnings available to FirstEnergy Corp. $965  $495  $(151) $1,309 
                 
                 
Changes Between 2008 and                
2007 Financial Results Increase (Decrease)                
Revenues:                
External                
Electric $732  $17  $-  $749 
Other  14   86   (24)  76 
Internal  -   67   (67)  - 
Total Revenues  746   170   (91)  825 
                 
Expenses:                
Fuel  (3)  165   -   162 
Purchased power  507   15   (67)  455 
Other operating expenses  17   (18)  (37)  (38)
Provision for depreciation  13   39   (13)  39 
Amortization of regulatory assets  34   -   -   34 
Deferral of new regulatory assets  208   -   -   208 
General taxes  19   2   3   24 
Total Expenses  795   203   (114)  884 
                 
Operating Income  (49)  (33)  23   (59)
Other Income (Expense):                
Investment income  (70)  (50)  59   (61)
Interest expense  46   20   (45)  21 
Capitalized interest  (8)  24   4   20 
Total Other Expense  (32)  (6)  18   (20)
                 
Income Before Income Taxes  (81)  (39)  41   (79)
Income taxes  (32)  (16)  (58)  (106)
Net Income  (49)  (23)  99   27 
Less: Noncontrolling interest income  -   -   (3)  (3)
Earnings available to FirstEnergy Corp. $(49) $(23) $102  $30 
70
Energy Delivery Services – 2008 Compared to 2007

Net income decreased $49 million to $916 million in 2008 compared to $965 million in 2007, primarily due to increased purchased power costs, decreased deferral of new regulatory assets and lower investment income, partially offset by higher revenues.

Revenues –

The increase in total revenues resulted from the following sources:

Revenues by Type of Service 2008  2007  
Increase
(Decrease)
 
  (In millions) 
Distribution services
 $3,882  $3,909  $(27)
Generation sales:
            
Retail
  5,768   5,393   375 
Wholesale
  962   694   268 
Total generation sales
  6,730   6,087   643 
Transmission
  1,267   1,118   149 
Other
  189   208   (19)
Total Revenues
 $12,068  $11,322  $746 

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

Electric Distribution KWH DeliveriesMet-EdEastern Pennsylvania553,000
PenelecWestern Pennsylvania590,000
WPSouthwest, South Central and Northern Pennsylvania718,000
MPNorthern, Central and Southeastern West Virginia387,000
PEWestern Maryland and Eastern West Virginia390,000
    
Residential
5,986,000		(0.9
)%
Commercial
(0.9
)%
Industrial
(3.9
)%
Total Distribution KWH Deliveries
(1.9
)%


Regulated Independent Transmission transmits electricity through transmission lines and its revenues are primarily derived from a formulaic rate that recovers costs and a return on investment for capital expenditures in connection with TrAIL, PATH and other projects, revenues from providing transmission services to electric energy providers and power marketers, and revenues from operating a portion of the FirstEnergy transmission system. Its results reflect the net transmission expenses related to the delivery of the respective generation loads.

Competitive Energy Services supplies, through FES and AE Supply, electric power to end-use customers through retail and wholesale arrangements, including competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland and the provision of partial POLR and default service for some utilities in Ohio, Pennsylvania and Maryland, including but not limited to the Utilities. This segment controls approximately 17,000 MWs of capacity (excluding approximately 2,700 MWs from unregulated plants expected to be closed by September 1, 2012) (see Note 11, Impairment of Long-Lived Assets of the Combined Notes to the Consolidated Financial Statements) and also purchases electricity to meet sales obligations. The segment's net income is primarily derived from electric generation sales less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO (prior to June 1, 2011)


51


to deliver energy to the segment's customers.
Other/Corporate contains corporate items and other businesses that are below the quantifiable threshold for separate disclosure as a reportable segment. (See Note 19, Segment Information of the Combined Notes to the Consolidated Financial Statements for further information on FirstEnergy's reportable operating segments.)
STRATEGY AND OUTLOOK

FirstEnergy's vision is to be a leading regional energy provider, recognized for operational excellence, outstanding customer service and our commitment to safety; the choice for long-term growth, investment value and financial strength; and a company driven by the leadership, skills, diversity and character of our employees.

FirstEnergy has grown over the last 15 years through several strategic mergers and asset transactions. Our most recent merger with Allegheny was completed in February 2011, significantly increasing our customer base and generating capacity and accelerating our movement further into eastern competitive markets. Also during 2011, we completed the transition to competitive markets in Pennsylvania and moved our ATSI assets into PJM, so that we now operate within a single regional transmission system.

FirstEnergy is uniquely positioned as the nation's largest contiguous electric system, with complementary assets across our generation, transmission and distribution delivery operations. These assets are in a prime location of PJM's competitive markets.

Our substantial regulated operations include 10 distribution utilities serving a balanced base of nearly 6 million customers across 5 states. We are also one of the largest owners of transmission assets in PJM with nearly 20,000 miles of high-voltage lines, including two independent transmission companies with significant assets. Combined, our utilities and transmission operations provide financial stability with strong cash flow and dividend support to FirstEnergy.

Our market-focused business model integrates more than 17,000 MWs of competitive generation, excluding approximately 2,700 MWs from unregulated plants expected to be closed by September 1, 2012, and are subject to review by PJM for reliability impacts(see Note 16, Commitment, Guarantees and Contingencies, regarding PJM's review of the our plans), with a multi-channel retail sales platform, providing a higher value for every MWH we generate. We primarily target customers in competitive markets close to our generation assets.

We believe we are well-positioned for upcoming environmental changes due to the considerable investments we have made in recent years to diversify our generation fleet and improve its environmental performance. As a result of the MATS rules recently finalized by the EPA, and other previously announced environmental regulations, FirstEnergy announced in early 2012 its intent to retire nine older coal-fired power plants, totaling 3,349 MW, located in Ohio, Pennsylvania, Maryland and West Virginia by September 1, 2012. When the retired fossil plants are removed from our fleet, nearly 100% percent of our generation output will be from either low or non-emitting facilities, including nuclear, hydro, natural gas and scrubbed coal units. This further positions our fleet to deliver superior value in the future.

We continue to face challenges related to macro-economic factors. These include slow economic recovery across portions of our service territory, which affect our distribution deliveries volumes to residential, commercial and industrial customers, and depressed natural gas and wholesale electricity prices, which affect revenues from our competitive retail business and generation fleet. However, we believe we are one of the better positioned companies in our industry to benefit from eventual increases in energy and capacity prices as economic conditions improve.

Financial Outlook

We intend to manage our operating and capital costs in order to achieve our financial goals and commitment to shareholders.

Our liquidity position remains strong, with approximately $49 million of short-term cash investments and over $4.3 billion of available liquidity as of January 31, 2012.

Positive earnings drivers for 2012 are expected to include:

▪A full year contribution from the Allegheny merger;

▪Higher competitive retail revenues as a result of continued growth in the business;

▪Lower fuel and operation and maintenance expenses due to the retirement of certain coal-fired plants in 2012 and from a continued focus on controlling our costs; and

▪Reduced interest expense as a result of debt redemptions during 2011.

Negative earnings drivers for 2012 are expected to include:

▪Lower margins for our competitive energy service business from depressed market prices of power and lower capacity


52


prices resulting from the PJM RPM auction beginning June 1, 2012;

▪Higher gross receipts taxes associated with increased competitive retail sales in Pennsylvania; and

▪Increased depreciation expenses from capital projects that were placed in service during 2011.

On January 5, 2012, we made a $600 million voluntary contribution to our pension plan bringing its funding level to 90% on an accumulated benefit obligation basis.

Capital Expenditures Outlook

Our capital expenditures in 2012 are estimated to be $2.1 billion (excluding nuclear fuel), a decrease of approximately $393 million from 2011. In addition to internal sources to fund capital requirements for 2012 and beyond, FirstEnergy expects to rely on external sources of funds.

Capital expenditures for our Regulated Distribution segment are forecast to decrease by $63 million in 2012 from $1.1 billion in 2011. The expected decrease primarily reflects the absence of storm restoration costs related to Hurricane Irene and the October 2011 snowstorm. For our Regulated Independent Transmission segment, capital expenditures are expected to decrease to $105 million in 2012 from $190 million in 2011. The decrease reflects the completion of TrAIL's 500-kV transmission line in electric2011.

Expenditures for Ohio and Pennsylvania energy efficiency and advanced metering initiatives are expected to be primarily recovered from distribution deliveriescustomers and federal stimulus funding. Other capital investments in our transmission and distribution infrastructure are planned to residentialsatisfy transmission capacity and commercial customers was primarily duereliability requirements, connect new load delivery and wholesale generation points, and achieve cost-effective improvements in the reliability of our service.

For our Competitive Energy Services segment, capital expenditures are expected to increase by $32 million to $803 million in 2012. The main drivers of the increase include steam generator replacement projects at Davis-Besse and Beaver Valley Unit 2 and turbine rotor replacement projects at Perry and Beaver Valley Unit 2. Other planned generation investments provide for maintenance of critical generation assets, delivering operational improvements to enhance reliability, supporting environmental compliance, and advancing our generation to market strategy.

For 2013, we anticipate baseline capital expenditures of approximately $2.0 billion, which exclude any potential additional strategic opportunities, future mandated spending, energy efficiency or environmental spending relating to MATS. Planned capital initiatives are intended to promote reliability, improve operations, and support current environmental and energy efficiency directives.

Environmental Outlook

We continually strive to enhance environmental protection and remain good stewards of our natural resources. We devote significant resources to environmental compliance efforts, and our employees share a commitment to, and accountability for, environmental performance. Our corporate focus on continuous improvement is integral to our environmental programs.

We have spent more than $10 billion on environmental protection efforts since the initial passage of the Clean Air and Water Acts in the 1970s, and these investments demonstrate our continuing commitment to the environment. Recent investments of $3.0 billion at our Hatfield, Fort Martin and Sammis Plants, further reduced summer usage resulting from milder weatheremissions of SO2 by over 95%, and NOx by at least 64% at these facilities. Since 1990, we have reduced emissions of NOx by more than 76%, SO2 by more than 86%, and mercury by approximately 56%.

We have taken aggressive steps over the past two decades that have increased our generating capacity without adding to overall CO2 emissions. For example, since 1990, we have reconfigured our fleet by retiring 1,312 MWs and committing to retire in 2008 compared tothe near future 3,349 MWs of older, coal-based generation and adding more than 1,800 MWs of non-emitting capacity. Through these and other actions, we have increased our generating capacity by nearly 15% over the same period while avoiding over 370 million metric tons of 2007, as cooling degree days decreased by 14.6%; heating degree days increased by 2.5%. In the industrial sector, a decrease in deliveries to automotive customers (18%) and steel customers (4%) was partially offset by an increase in usage by refining customers (3%).

The following table summarizes the price and volume factors contributing to the $643 million increase in generation revenues in 2008 compared to 2007:

  Increase 
Sources of Change in Generation Revenues (Decrease) 
  (In millions) 
Retail:    
Effect of 1.9% decrease in sales volumes $(103)
Change in prices  478 
   375 
Wholesale:    
Effect of 0.1% increase in sales volumes  1 
Change in prices  267 
   268 
Net Increase in Generation Revenues $643 

The decrease in retail generation sales volumes was primarily due to milder weather and economic conditions in the Utilities' service territories and an increase in customer shopping for Penn, Penelec and JCP&L. The increase in retail generation prices in 2008 was due to higher generation rates for JCP&L resulting from the New Jersey BGS auctions effective June 1, 2007 and June 1, 2008, and the Ohio Companies' fuel cost recovery riders that became effective in January 2008. The increase in wholesale prices reflected higher spot market prices for PJM market participants.

Transmission revenues increased $149 million due to higher transmission rates for Met-Ed and Penelec resulting from the annual update to their TSC riders in mid-2008 and the Ohio Companies' PUCO-approved transmission tariff increases that became effective July 1, 2007 and July 1, 2008. The difference between transmission revenues accrued and transmission expenses incurred is deferred, resulting in no material impact to current period earnings.

71

Expenses –

The net revenue increase discussed above was more than offset by a $795 million increase in expenses due to the following:

·
Purchased power costs were $507 million higher in 2008 due to higher unit costs and a decrease in the amount of NUG costs deferred. The increase in unit costs from non-affiliates was primarily due to higher costs for JCP&L resulting from the BGS auction process. JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. Higher unit costs from FES reflect the increases in the Ohio Companies' retail generation rates, as provided for under the PSA then in effect with FES. The decrease in purchase volumes was due to the lower retail generation sales requirements described above.CO2 emissions.

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 $456 
Change due to decreased volumes  (128)
   328 
Purchases from FES:    
Change due to increased unit costs  110 
Change due to decreased volumes  (44)
   66 
     
Decrease in NUG costs deferred  113 
Net Increase in Purchased Power Costs $507 

·
Other operating expenses increased $17 million due primarily to the net effect of the following:

-a $69 million increase primarily for reduced intersegment credits associated with the Ohio Companies' nuclear generation leasehold interests and increased MISO transmission-related expenses;

-
a $15 million decrease for contractor costs associated with vegetation management activities, as more of that work performed in 2008 related to capital projects;

-a $13 million decrease in uncollectible expense due primarily to the recognition of higher uncollectible reserves in 2007 and enhanced collection processes in 2008;

-lower labor costs charged to operating expense of $12 million, as a greater proportion of labor was devoted to capital-related projects in 2008; and

-a $6 million decline in regulatory program costs, including customer rebates.

·Amortization of regulatory assets increased $34 million due primarily to higher transition cost amortization for the Ohio Companies, partially offset by decreases at JCP&L for regulatory assets that were fully recovered at the end of 2007 and in the first half of 2008.
·The deferral of new regulatory assets during 2008 was $208 million lower than in 2007. MISO transmission deferrals and RCP fuel deferrals decreased $166 million, as more transmission and generation costs were recovered from customers through PUCO-approved riders. Also contributing to the decrease was the absence of the one-time deferral in 2007 of decommissioning costs related to the Saxton nuclear research facility ($27 million) and lower PJM transmission cost deferrals ($32 million), partially offset by increased societal benefit deferrals ($15 million).

·Higher depreciation expense of $13 million resulted from additional capital projects placed in service since 2007.

·General taxes increased $19 million due to higher gross receipts taxes, property taxes and payroll taxes.

72
Other Expense –

Other expense increased $32 millionWe have taken a leadership role in 2008 comparedpursuing new ventures to 2007 due to lower investment income of $70 million, resulting primarily from the repayment of notes receivable from affiliates, partially offset by lower interest expense (net of capitalized interest) of $38 million. The interest expense declined for the Ohio Companies due to their redemption of certain pollution control notestest and develop new technologies that may achieve additional reductions in the second half of 2007.CO2 emissions. These include:

Competitive Energy Services – 2008 Compared to 2007

Net income for this segment was $472Sales of over 1 million in 2008 compared to $495 million in 2007. The $23 million reduction in net income reflects a decrease in gross generation margin (revenue less fuel and purchased power) and higher depreciation expense, which were partially offset by lower other operating expenses.

Revenues –MWH per year of wind generation.

Total revenues increased $170 million in 2008 comparedCO2 sequestration testing to 2007. This increase primarily resulted from higher unit prices on affiliated generation sales togain a better understanding of the Ohio Companies and increased non-affiliated wholesale sales, partially offset by lower retail sales.potential for geological storage of CO2.

The increase in reported segment revenues resultedSupporting afforestation - growing forests on non-forested land - and other efforts designed to remove CO2 from the following sources:

Revenues by Type of Service 2008  2007  
Increase
(Decrease)
 
  (In millions) 
Non-Affiliated Generation Sales:
         
Retail
 $615  $712  $(97)
Wholesale
  717   603   114 
Total Non-Affiliated Generation Sales
  1,332   1,315   17 
Affiliated Generation Sales
  2,968   2,901   67 
Transmission
  150   103   47 
Other
  89   50   39 
Total Revenues
 $4,539  $4,369  $170 

The lower retail revenues reflect reduced commercial and industrial contract renewals in the PJM market and the termination of certain government aggregation programs in MISO. Higher non-affiliated wholesale revenues resulted from higher capacity prices and increased sales volumes in PJM, partially offset by decreased sales volumes in MISO.

The increased affiliated company generation revenues were due to higher unit prices for the Ohio Companies partially offset by lower unit prices for the Pennsylvania Companies and decreased affiliated sales volumes. The higher unit prices reflected fuel-related increases in the Ohio Companies’ retail generation rates. While unit prices for each of the Pennsylvania Companies did not change, the mix of sales among the companies caused the overall price to decline. The reduction in PSA sales volumes to the Ohio and Pennsylvania Companies was due to the milder weather and industrial sales changes discussed above and reduced default service requirements in Penn’s service territory as a result of its RFP process.

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 15.8% decrease in sales volumes $(113)
Change in prices  
16
 
   
(97
)
Wholesale:    
Effect of 3.8% increase in sales volumes  23 
Change in prices  
91
 
   
114
 
Net Increase in Non-Affiliated Generation Revenues 
$
17
 
73
  Increase 
Source of Change in Affiliated Generation Revenues
 
(Decrease)
 
  (In millions) 
Ohio Companies:    
Effect of 1.5% decrease in sales volumes $(34)
Change in prices  
129
 
   
95
 
Pennsylvania Companies:    
Effect of 1.5% decrease in sales volumes  (10)
Change in prices  
(18
)
   
(28
)
Net Increase in Affiliated Generation Revenues 
$
67
 

Transmission revenues increased $47 million due primarily to higher transmission rates in MISO and PJM.

Expenses –

Total expenses increased $203 million in 2008 due to the following factors:

·Fossil fuel costs increased $155 million due to higher unit prices ($163 million) partially offset by lower generation volume ($8 million). The increased unit prices primarily reflect increased rates for existing eastern coal contracts, higher transportation surcharges and emission allowance costs in 2008. Nuclear fuel expense was $10 million higher as nuclear generation increased in 2008.

·Purchased power costs increased $15 million due primarily to higher spot market and capacity prices, partially offset by reduced volume requirements.

·Fossil operating costs decreased $22 million due to a gain on the sale of a coal contract in the fourth quarter of 2008 ($20 million), reduced scheduled outage activity ($17 million) and increased gains from emission allowance sales ($7 million), partially offset by costs associated with a cancelled electro-catalytic oxidation project ($13 million) and a $7 million increase in labor costs.

·Transmission expense decreased $35 million due to reduced congestion costs.

·Other operating costs increased $39 million due primarily to the assignment of CEI’s and TE’s leasehold interests in the Bruce Mansfield Plant to FGCO in the fourth quarter of 2007 ($31 million) and reduced life insurance investment values, partially offset by lower associated company billings and employee benefit costs.

·Higher depreciation expenses of $39 million were due to the assignment of the Bruce Mansfield Plant leasehold interests to FGCO and NGC’s purchase of certain lessor equity interests in Perry and Beaver Valley Unit 2.

Other Expense –environment.

Total other expenseReducing emissions of SF6 (sulfur hexafluoride) by nearly 15 metric tons, resulting in 2008 was $6 million higher than in 2007, principally due to a $50 million decrease in net earnings from nuclear decommissioning trust investments due primarily to securities impairments resulting from market declines during 2008, partially offset by a decline in interest expense (netan equivalent reduction of capitalized interest)nearly 315,000 metric tons of $44 million fromCO2, through the repayment of notes to affiliates since 2007.EPA's SF6 Emissions Reduction Partnership for Electric Power Systems.


Other – 2008 Compared to 2007

Our financial results from other operating segments53


Supporting research to develop and reconciling items resulted in a $105 million increase in net income in 2008 compared to 2007.evaluate cost effective sorbent materials for CO2 capture including work by EPRI and The increase resulted primarily from a $19 million after-tax gain from the saleUniversity of telecommunication assets, a $10 million after-tax gain from the settlement of litigation relating to formerly-owned international assets, a $41 million reduction in interest expense associated with the revolving credit facility, and income tax adjustments associated with the favorable settlement of tax positions taken on federal returns in prior years. These increases were partially offset by the absence of the gain from the sale of First Communications ($13 million, net of taxes) in 2007.

74
POSTRETIREMENT BENEFITSAkron.

We provide a noncontributory qualified defined benefit pension plan that covers substantially allremain actively engaged in the federal and state debate over future environmental requirements and legislation. We actively work with policy makers and regulators to develop fair and reasonable requirements, with the goal of reducing emissions while minimizing the economic impact on our employees and non-qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and compensation levels. We also provide health care benefits, which include certain employee contributions, deductibles, and co-payments, upon retirementcustomers. Due to employees hired priorthe significant uncertainty as to January 1, 2005, their dependents, and under certain circumstances, their survivors. Our benefit plan assets and obligations are remeasured annually using a December 31 measurement date. Adverse market conditions during 2008 increased 2009 costs, which were partially offset by the effectsfinal form or timing of a $500 million voluntary cash pension contributionsignificant number of regulations and legislation at both the federal and state levels, we are unable to determine the potential impact and risks associated with all future environmental requirements. The CSAPR was stayed at the end of 2011 and the federal appeals court reviewing CSAPR has scheduled an OPEB plan amendmentApril 13, 2012 hearing. The new MATS were finalized at the end of 2011, which resulted in 2009 (see Note 3). Strengthened equity markets during 2007 and a $300 million voluntary cash pension contribution made in 2007 contributedour decision to the reductions in postretirement benefits expenses in 2008. Pension and OPEB expenses are included in variousretire nine older coal-fired generation plants by September 1, 2012. Our current estimate is that it may cost categories and have contributedapproximately $1.3 - $1.7 billion to cost increases discussed above for 2009. The following table reflects the portion of qualified and non-qualified pension and OPEB costs that were charged to expense in the three years ended December 31, 2009:bring our remaining units into compliance.

Postretirement Benefits Expense (Credits) 2009 2008 2007 
  (In millions) 
Pension
  $185  $(23) $6 
OPEB
   (40)  (37)  (41)
Total
  $145  $(60) $(35)
We also have a long history of supporting research in distributed energy resources. Distributed energy resources include fuel cells, solar and wind systems or energy storage technologies located close to the customer or direct control of customer loads to provide alternatives or enhancements to the traditional electric power system. We are testing the world's largest utility-scale fuel cell system to determine its feasibility for augmenting generating capacity during summer peak-use periods. Through a partnership with EPRI, the Cuyahoga Valley National Park, the Department of Defense and Case Western Reserve University, two solid-oxide fuel cells were installed as part of a test program to explore the technology and the environmental benefits of distributed generation.

AsWe are also evaluating the impact of December 31, 2009,distributed energy storage on the distribution system through analysis and field demonstrations of advanced battery technologies. FirstEnergy's EasyGreen® load-management program utilizes two-way communication capability with customers' non-critical equipment, such as air conditioners in New Jersey and Pennsylvania, to help manage peak loading on the electric distribution system. We have also made an online interactive energy efficiency tool, Home Energy Analyzer, available to our pension plan was underfunded and we currently anticipate that additional cash contributions will be required in 2012 for the 2011 plan year. The overall actual investment result during 2009 was a gain of 13.6% comparedcustomers to an assumed 9% return. Based on discount rates of 6% for pension and 5.75% for OPEB, 2010 pre-tax net periodic pension and OPEB expense will be approximately $89 million.help achieve electricity use reduction goals.

SUPPLY PLAN

Regulated Commodity Sourcing

TheCertain of the Utilities have a default service obligationobligations to provide the required power supply to non-shopping customers who have elected to continue to receive service under regulated retail tariffs. The volume of these sales can vary depending on the level of shopping that occurs. Supply plans vary by state and by service territory. JCP&L’s default service or BGS supply is secured through a statewide competitive procurement process approved by the NJBPU. The Ohio UtilitiesCompanies', Pennsylvania Companies' and Penn’sPE's Maryland default service supplies are provided through a competitive procurement process approved by the PUCO (under the ESP), PPUC (under the DSP) and PPUC,MDPSC (under the SOS), respectively. The default service supply for Met-Ed and Penelec is secured through a FERC-approved agreement with FES. If any unaffiliated suppliers failsupplier fails to deliver power to any one of thethose Utilities’ service areas, the Utility serving that area may need to procure the required power in the market in their role as a PLR.

POLR. West Virginia electric generation continues to be regulated by the WVPSC.
Unregulated Commodity Sourcing

The Competitive Energy Services segment, through FES has retail and wholesale competitive load-serving obligations in Ohio, New Jersey, Maryland, Pennsylvania, Michigan and Illinois serving both affiliated and non-affiliated companies. FES provides energy products and services to customers under various PLR, shopping, competitive-bid and non-affiliated contractual obligations. In 2009, FES’ generation was used to serve two main obligations -- affiliated companies utilized approximately 76% of its total generation and direct retail customers utilized approximately 18% of FES' total generation. Geographically, approximately 67% of FES’ obligation is located in the MISO market area and 33% is located in the PJM market area.

FESAE Supply, provides energy and energy related services, including the generation and sale of electricity and energy planning and procurement through retail and wholesale competitive supply arrangements. FES controls (either through ownership, lease, affiliated power contracts or participation in OVEC) 14,346 MW of installed generating capacity. FES supplies the power requirements of its competitive load-serving obligations through a combination of subsidiary-owned generation, non-affiliated contracts and spot market transactions.
FES and AE Supply have retail and wholesale competitive load-serving obligations in Ohio, Pennsylvania, Illinois, Maryland, Michigan and New Jersey, serving both affiliated and non-affiliated companies. FES and AE Supply provide energy products and services to customers under various POLR, shopping, competitive-bid and non-affiliated contractual obligations. Geographically, most of FES’ and AE Supply's obligations are in the PJM market area where all of its respective generation facilities are located.
Regional Reliability
All of FirstEnergy's facilities are located within PJM and operate under the reliability oversight of a regional entity known as RFC. This regional entity operates under the oversight of the NERC in accordance with a Delegation Agreement approved by the FERC. RFC began operations under the NERC on January 1, 2006. On July 20, 2006, the NERC was certified by the FERC as the ERO


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in the United States pursuant to Section 215 of the FPA and RFC was certified as a regional entity.
Competition
As a result of actions taken by state legislative bodies, major changes in the electric utility business have occurred in portions of the United States, including Ohio, New Jersey, Pennsylvania and Maryland, where most of FirstEnergy utility subsidiaries operate. These changes have altered the way traditional integrated utilities conduct their business. FirstEnergy has aligned its business units to participate in the competitive electricity marketplace (see Management's Discussion and Analysis for more information regarding FirstEnergy's Competitive Energy Services segment).
FirstEnergy's Competitive Energy Services segment participates in deregulated energy markets in Ohio, Pennsylvania, Maryland, Michigan, New Jersey and Illinois, through FES and AE Supply. In these markets, the Competitive Energy Services segment competes: (1) to provide retail generation service directly to end users; (2) to provide wholesale generation service to utilities, municipalities and co-operatives, which, in turn, resell to their end users, and (3) in the wholesale market. The success of the Competitive Energy Services segment is driven by its ability to successfully compete against other retail markets and/or generators and to produce revenues that exceed costs.
Seasonality
The sale of electric power is generally a seasonal business and weather patterns can have a material impact on FirstEnergy’s operating results. Demand for electricity in our service territories historically peaks during the summer and winter months, with market prices also generally peaking at that time. Accordingly, FirstEnergy’s annual results of operations and liquidity position may depend disproportionately on its operating performance during the summer and winter. Mild weather conditions may result in lower power sales and consequently lower earnings.
Research and Development
The Utilities, FES, FGCO and FENOC participate in the funding of EPRI, which was formed for the purpose of expanding electric R&D under the voluntary sponsorship of the nation’s electric utility industry — public, private and cooperative. Its goal is to mutually benefit utilities and their customers by promoting the development of new and improved technologies to help the utility industry meet present and future electric energy needs in environmentally and economically acceptable ways. EPRI conducts research on all aspects of electric power production and use, including fuels, generation, delivery, energy management and conservation, environmental effects and energy analysis. The majority of EPRI’s research and development projects are directed toward practical solutions and their applications to problems currently facing the electric utility industry.
FirstEnergy participates in other initiatives with industry R&D consortiums and universities to address technology needs for its various business units. Participation in these consortiums helps the company address research needs in areas such as plant operations and maintenance, major component reliability, environmental controls, advanced energy technologies, and transmission and distribution system infrastructure to improve performance, and develop new technologies for advanced energy and grid applications.


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Executive Officers
Name Age Positions Held During Past Five Years Dates
A. J. Alexander 60  President and Chief Executive Officer (A)(B) *-present
    Chief Executive Officer (F) *-present
    President and Chief Executive Officer (H) 2011-present
    President (C)(D) *-2008
       
L. M. Cavalier 60  Senior Vice President, Human Resources (B) *-present
    Senior Vice President, Human Resources (H) 2011-present
       
M. T. Clark 61  President and Chief Financial Officer (G)(L) 2012-present
    Executive Vice President and Chief Financial Officer (A)(B)(C)(D)(E)(F) 2009-present
    Executive Vice President and Chief Financial Officer (H)(I)(J)(K) 2011-present
    Executive Vice President and Chief Financial Officer (G) 2011
    Executive Vice President, Strategic Planning & Operations (A)(B) 2008-2009
    Senior Vice President, Strategic Planning & Operations (B) *-2008
       
M. J. Dowling 47 Senior Vice President, External Affairs (B)(H) 2011-present
    Vice President, External Affairs (B) 2010-2011
    Vice President, Communications (B) 2008-2010
    Vice President, Governmental Affairs (B) 2007-2008
    Vice President (B) *-2007
       
C. E. Jones 56  Senior Vice President & President, FirstEnergy Utilities (B) 2010-present
    Senior Vice President & President, FirstEnergy Utilities (H) 2011-present
    President (J)(K) 2011-present
    President (C)(D) 2010-present
    Senior Vice President & President, FirstEnergy Utilities (A) 2010-2011
    Senior Vice President, Energy Delivery & Customer Service (B) 2009-2010
    President (E) 2007-2009
    Senior Vice President (B)(C)(D) *-2007
       
J. H. Lash 61  President FE, Generation (B)(H) 2011-present
    Chief Nuclear Officer (F) 2011-present
    President (I) 2011-present
    President and Chief Nuclear Officer (F) 2010-2011
    Senior Vice President and Chief Operating Officer (F) 2007-2010
    Vice President, Beaver Valley (F) *-2007
       
G. R. Leidich 61  Executive Vice President, Integration (A)(B)(H)(M) 2011
    President (G)(M) 2011
    Executive Vice President & President, FirstEnergy Generation (A)(B)(M) 2008-2011
    Senior Vice President, Operations (B) 2007-2008
    President and Chief Nuclear Officer (F) *-2007
       
J. F. Pearson 57  Vice President and Treasurer (A)(B)(C)(D)(E)(F) *-present
    Vice President and Treasurer (G)(H)(I)(J)(K) 2011-present
       
D. R. Schneider 50  President (E) 2009-present
    Senior Vice President, Energy Delivery & Customer Service (B) 2007-2009
    Senior Vice President (C)(D) 2007-2009
    Vice President (B) *-2007
       
L. L. Vespoli 52  Executive Vice President and General Counsel (A)(B)(C)(D)(E)(F) 2008-present
    Executive Vice President and General Counsel (G)(H)(I)(J)(K) 2011-present
    Senior Vice President and General Counsel (A)(B)(C)(D)(E)(F) *-2008
       
H. L. Wagner 59  Vice President, Controller and Chief Accounting Officer (A) *-present
    Vice President and Controller (C)(D)(E)(F) *-present
    Vice President and Controller (G)(I)(J)(K) 2011-present
    Vice President, Controller and Chief Accounting Officer (H) 2011-present
    Vice President, Controller and Chief Accounting Officer (B) 2010-present
    Vice President and Controller (B) *-2010
* Indicates position held at least since January 1, 2007(E) Denotes executive officer of FES(J) Denotes executive officer of MP, PE and WP
(A) Denotes executive officer of FE(F) Denotes executive officer of FENOC(K) Denotes executive officer of TrAIL
(B) Denotes executive officer of FESC(G) Denotes executive officer of AE(L) Position effective January 1, 2012
(C) Denotes executive officer of OE, CEI and TE(H) Denotes executive officer of AESC(M) Retired on December 31, 2011
(D) Denotes executive officer of Met-Ed, Penelec and Penn(I) Denotes executive officer of AGC


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Employees
As of December 31, 2011, FirstEnergy’s subsidiaries had 17,257 employees located in the United States as follows:
 
Total
Employees
 
Bargaining
Unit
Employees
FESC2,975
 293
AESC(1)
3,971
 1,177
OE1,222
 714
CEI897
 608
TE390
 290
Penn204
 153
JCP&L1,413
 1,090
Met-Ed678
 488
Penelec896
 638
ATSI38
 —
FES273
 —
FGCO1,652
 1,061
FENOC2,648
 957
Total17,257
 7,469
(1)
AESC employs substantially all of the former Allegheny personnel who provide services to AE and its subsidiaries, including AE Supply, AGC, MP, PE, WP and TrAIL.
FirstEnergy Web Site
Each of the registrant’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are also made available free of charge on or through FirstEnergy’s internet Web site at www.firstenergycorp.com. These reports are posted on the Web site as soon as reasonably practicable after they are electronically filed with the SEC. Additionally, we routinely post important information on our Web site and recognize our Web site as a channel of distribution to reach public investors and as a means of disclosing material non-public information for complying with disclosure obligations under the SEC's Regulation FD. Information contained on FirstEnergy’s Web site shall not be deemed incorporated into, or to be part of, this report.
In accordance with SEC rules, FirstEnergy will include disclosure of any amendment or waiver to its Code of Ethics or a provision of that Code on its Internet Web site within four business days following the date of any such amendment or waiver.
ITEM 1A.RISK FACTORS
We operate in a business environment that involves significant risks, many of which are beyond our control. Management of each Registrant regularly evaluates the most significant risks of the Registrant’s businesses and reviews those risks with the FirstEnergy Board of Directors or appropriate Committees of the Board. The following risk factors and all other information contained in this report should be considered carefully when evaluating FirstEnergy and our subsidiaries. These risk factors could affect our financial results and cause such results to differ materially from those expressed in any forward-looking statements made by or on behalf of us. Below, we have identified risks we currently consider material. Additional information on risk factors is included in “Item 1. Business” and “Item 7. Management’s Discussion and Analysis of Registrant and Subsidiaries” and in other sections of this Form 10-K that include forward-looking and other statements involving risks and uncertainties that could impact our business and financial results.
Risks Related to Business Operations
Risks Arising from the Reliability of Our Power Plants and Transmission and Distribution Equipment
Operation of generation, transmission and distribution facilities involves risk, including the risk of potential breakdown or failure of equipment or processes due to aging infrastructure, fuel supply or transportation disruptions, accidents, labor disputes or work stoppages by employees, acts of terrorism or sabotage, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions resulting from environmental limitations and governmental interventions, and performance below expected levels. In addition, weather-related incidents and other natural disasters can disrupt generation, transmission and distribution delivery systems. Because our transmission facilities are interconnected with those of third parties, the operation of our facilities could be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties.


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Operation of our power plants below expected capacity could result in lost revenues and increased expenses, including higher operating and maintenance costs, purchased power costs and capital requirements. Unplanned outages of generating units and extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of our business. Unplanned outages typically increase our operation and maintenance expenses and may reduce our revenues as a result of selling fewer MWH or may require us to incur significant costs as a result of operating our higher cost units or obtaining replacement power from third parties in the open market to satisfy our forward power sales obligations. Moreover, if we were unable to perform under contractual obligations, penalties or liability for damages could result.
FES, FGCO and the Ohio Companies are exposed to losses under their applicable sale-leaseback arrangements for generating facilities upon the occurrence of certain contingent events that could render those facilities worthless. Although we believe these types of events are unlikely to occur, FES, FGCO and the Ohio Companies have a maximum exposure to loss under those provisions of approximately $1.4 billion for FES, $606 million for OE and an aggregate of $587 million for TE and CEI as co-lessees.
We remain obligated to provide safe and reliable service to customers within our franchised service territories. Meeting this commitment requires the expenditure of significant capital resources. Failure to provide safe and reliable service and failure to meet regulatory reliability standards due to a number of factors, including, but not limited to, equipment failure and weather, could adversely affect our operating results through reduced revenues and increased capital and operating costs and the imposition of penalties/fines or other adverse regulatory outcomes.
Changes in Commodity Prices Could Adversely Affect Our Profit Margins
We purchase and sell electricity in the competitive wholesale and retail markets. Increases in the costs of fuel for our generation facilities (particularly coal, uranium and natural gas) can affect our profit margins. Changes in the market price of electricity, which are affected by changes in other commodity costs and other factors, may impact our results of operations and financial position by increasing the amount we pay to purchase power to supply POLR and default service obligations in the states we do business. In addition, the global economy could lead to lower international demand for coal, oil and natural gas, which may lower fossil fuel prices and put downward pressure on electricity prices.
Electricity and fuel prices may fluctuate substantially over relatively short periods of time for a variety of reasons, including:
changing weather conditions or seasonality;
changes in electricity usage by our customers;
illiquidity and credit worthiness of participants in wholesale power and other markets;
transmission congestion or transportation constraints, inoperability or inefficiencies;
availability of competitively priced alternative energy sources;
changes in supply and demand for energy commodities;
changes in power production capacity;
outages at our power production facilities or those of our competitors;
changes in production and storage levels of natural gas, lignite, coal, crude oil and refined products;
changes in legislation and regulation; and
natural disasters, wars, acts of sabotage, terrorist acts, embargoes and other catastrophic events.
We Are Exposed to Operational, Price and Credit Risks Associated With Selling and Marketing Products in the Power Markets That We Do Not Always Completely Hedge Against
We purchase and sell power at the wholesale level under market-based tariffs authorized by the FERC, and also enter into agreements to sell available energy and capacity from our generation assets. If we are unable to deliver firm capacity and energy under these agreements, we may be required to pay damages. These damages would generally be based on the difference between the market price to acquire replacement capacity or energy and the contract price of the undelivered capacity or energy. Depending on price volatility in the wholesale energy markets, such damages could be significant. Extreme weather conditions, unplanned power plant outages, transmission disruptions, and other factors could affect our ability to meet our obligations, or cause increases in the market price of replacement capacity and energy.
We attempt to mitigate risks associated with satisfying our contractual power sales arrangements by reserving generation capacity to deliver electricity to satisfy our net firm sales contracts and, when necessary, by purchasing firm transmission service. We also routinely enter into contracts, such as fuel and power purchase and sale commitments, to hedge our exposure to fuel requirements and other energy-related commodities. We may not, however, hedge the entire exposure of our operations from commodity price


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volatility. To the extent we do not hedge against commodity price volatility, our results of operations and financial position could be negatively affected.
The Use of Derivative Contracts by Us to Mitigate Risks Could Result in Financial Losses That May Negatively Impact Our Financial Results
We use a variety of non-derivative and derivative instruments, such as swaps, options, futures and forwards, to manage our commodity and financial market risks. In the absence of actively quoted market prices and pricing information from external sources, the valuation of some of these derivative instruments involves management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of some of these contracts. Also, we could recognize financial losses as a result of volatility in the market values of these contracts or if a counterparty fails to perform.
Financial Derivatives Reforms Could Increase Our Liquidity Needs and Collateral Costs and Impose Additional Regulatory Burdens
In July 2010, federal legislation was enacted to reform financial markets that significantly alter how OTC derivatives are regulated. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank) increased regulatory oversight of OTC derivatives, including (1) requiring standardized OTC derivatives to be traded on registered exchanges regulated by the CFTC, (2) imposing new and potentially higher capital and margin requirements and (3) authorizing the establishment of overall volume and position limits. The law gives the CFTC authority to exempt companies that participate in the swap market as “end users” for hedging purposes which could reduce, but not eliminate, the applicability of these measures to us. These requirements could cause our OTC transactions to be more costly and have an adverse effect on our liquidity due to additional capital requirements. In addition, as these reforms aim to standardize OTC products it could limit the effectiveness of our hedging programs because we would have less ability to tailor OTC derivatives to match the precise risk we are seeking to protect.
We rely on the OTC derivative markets as part of our program to hedge the price risk associated with our power portfolio. The effect on our operations of this legislation will depend in part on whether we are determined to be a swap dealer, a major swap participant or a qualifying end-user through a self-identification process, based on the meaning of those terms to be established in the final rules. If we are determined to be a swap dealer or a major swap participant, we will be required to register with the CFTC and execute most bilateral OTC derivative transactions through an exchange or central clearinghouse. This requirement could require us to commit substantial additional capital to cover increases in collateral costs associated with margin requirements of the major exchanges. We would also be required to comply with increased reporting and record-keeping requirements and follow CFTC-specified business conduct standards, and adhere to position limits in a potentially broad range of energy commodities.
Even if we are not determined to be a swap dealer or a major swap participant, we will be required to comply with additional regulatory obligations under Dodd-Frank, which includes some reporting requirements, clearing some additional transactions that we would otherwise enter into over-the-counter, and having to adhere to position limits. Also, the total burden that the rules could impose on all market participants could cause liquidity in the bilateral OTC swap market to decrease substantially. The new rules could impede our ability to meet our hedge targets in a cost-effective manner. FirstEnergy cannot predict the ultimate outcome that Dodd-Frank will have on its results of operations, cash flows or financial position.
Our Risk Management Policies Relating to Energy and Fuel Prices, and Counterparty Credit, Are by Their Very Nature Risk Related, and We Could Suffer Economic Losses Despite Such Policies
We attempt to mitigate the market risk inherent in our energy, fuel and debt positions. Procedures have been implemented to enhance and monitor compliance with our risk management policies, including validation of transaction and market prices, verification of risk and transaction limits, sensitivity analysis and daily portfolio reporting of various risk measurement metrics. Nonetheless, we cannot economically hedge all of our exposures in these areas and our risk management program may not operate as planned. For example, actual electricity and fuel prices may be significantly different or more volatile than the historical trends and assumptions reflected in our analyses. Also, our power plants might not produce the expected amount of power during a given day or time period due to weather conditions, technical problems or other unanticipated events, which could require us to make energy purchases at higher prices than the prices under our energy supply contracts. In addition, the amount of fuel required for our power plants during a given day or time period could be more than expected, which could require us to buy additional fuel at prices less favorable than the prices under our fuel contracts. As a result, we cannot always predict the impact that our risk management decisions may have on us if actual events lead to greater losses or costs than our risk management positions were intended to hedge.
Our risk management activities, including our power sales agreements with counterparties, rely on projections that depend heavily on judgments and assumptions by management of factors such as future market prices and demand for power and other energy-related commodities. These factors become more difficult to predict and the calculations become less reliable the further into the future these estimates are made. Even when our policies and procedures are followed and decisions are made based on these estimates, results of operations may be diminished if the judgments and assumptions underlying those calculations prove to be inaccurate.
We also face credit risks from parties with whom we contract who could default in their performance, in which cases we could be forced to sell our power into a lower-priced market or make purchases in a higher-priced market than existed at the time of executing


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the contract. Although we have established risk management policies and programs, including credit policies to evaluate counterparty credit risk, there can be no assurance that we will be able to fully meet our obligations, that we will not be required to pay damages for failure to perform or that we will not experience counterparty non-performance or that we will collect for voided contracts. If counterparties to these arrangements fail to perform, we may be forced to enter into alternative hedging arrangements or honor underlying commitments at then-current market prices. In that event, our financial results could be adversely affected.
Nuclear Generation Involves Risks that Include Uncertainties Relating to Health and Safety, Additional Capital Costs, the Adequacy of Insurance Coverage and Nuclear Plant Decommissioning
We are subject to the risks of nuclear generation, including but not limited to the following:
the potential harmful effects on the environment and human health resulting from unplanned radiological releases associated with the operation of our nuclear facilities and the storage, handling and disposal of radioactive materials;
limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with our nuclear operations or those of others in the United States;
uncertainties with respect to contingencies and assessments if insurance coverage is inadequate; and
uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed operation including increases in minimum funding requirements or costs of completion.
The NRC has broad authority under federal law to impose licensing security and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines and/or shut down a unit, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants, including ours. Also, a serious nuclear incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or relicensing of any domestic nuclear unit. See "Potential NRC Regulation in Response to the Incident at Japan's Fukushima Daiichi Nuclear Plant Could Adversely Effect Our Business and Financial Condition" below and Note 16, Commitments, Guarantees and Contingencies - Environmental Matters of the Combined Notes to the Consolidated Financial Statements.
We Have a Significant Percentage of Coal-Fired Generation Capacity Which Exposes us to Risk from Regulations Relating to Coal and Coal Combustion Residuals
Approximately 65% of FirstEnergy's generation fleet capacity is coal-fired. Historically, coal-fired generating plants face greater exposure to the costs of complying with federal, state and local environmental statutes, rules and regulations relating to emissions of SO2 and NOx. In addition, the MATS established coal-fired emission standards for mercury, hydrochloric acid and various metals effective in April 2015, proposed coal combustion residual regulations include an option to reclassify coal ash as a hazardous waste, and there are currently a number of federal, state and international initiatives under consideration to, among other things, require reductions in GHG emissions. These legal requirements and initiatives could require substantial additional costs, extensive mitigation efforts and, in the case of GHG requirements, could raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities. Failure to comply with any such existing or future legal requirements may also result in the assessment of fines and penalties. Significant resources also may be expended to defend against allegations of violations of any such requirements.
Capital Market Performance and Other Changes May Decrease the Value of Pension Fund Assets, Decommissioning and Other Trust Funds Which Then Could Require Significant Additional Funding
Our financial statements reflect the values of the assets held in trust to satisfy our obligations to decommission our nuclear generation facilities and under pension and other postemployment benefit plans. The value of certain of the assets held in these trusts do not have readily determinable market values. Changes in the estimates and assumptions inherent in the value of these assets could affect the value of the trusts. If the value of the assets held by the trusts declines by a material amount, our funding obligation to the trusts could materially increase. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. Forecasting investment earnings and costs to decommission nuclear generating stations, to pay future pensions and other obligations requires significant judgment, and actual results may differ significantly from current estimates. Capital market conditions that generate investment losses or increase the present value of liabilities can negatively impact our results of operations and financial position.
We Could be Subject to Higher Costs and/or Penalties Related to Mandatory Reliability Standards Set by NERC/FERC or Changes in the Rules of Organized Markets and the States in Which We Do Business
As a result of the EPACT, owners, operators, and users of the bulk electric system are subject to mandatory reliability standards promulgated by the NERC and approved by FERC as well as mandatory reliability standards and energy efficiency requirements imposed by each of the states in which we operate. The standards are based on the functions that need to be performed to ensure that the bulk electric system operates reliably. Compliance with modified or new reliability standards may subject us to higher operating costs and/or increased capital expenditures. If we were found not to be in compliance with the mandatory reliability


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standards, we could be subject to sanctions, including substantial monetary penalties.
Reliability standards that were historically subject to voluntary compliance are now mandatory and could subject us to potential civil penalties for violations which could negatively impact our business. The FERC can now impose penalties of $1.0 million per day for failure to comply with these mandatory electric reliability standards.
In addition to direct regulation by the FERC and the states, we are also subject to rules and terms of participation imposed and administered by various RTOs and ISOs. Although these entities are themselves ultimately regulated by the FERC, they can impose rules, restrictions and terms of service that are quasi-regulatory in nature and can have a material adverse impact on our business. For example, the independent market monitors of ISOs and RTOs may impose bidding and scheduling rules to curb the potential exercise of market power and to ensure the market functions. Such actions may materially affect our ability to sell, and the price we receive for, our energy and capacity. In addition, the RTOs may direct our transmission owning affiliates to build new transmission facilities to meet the reliability requirements of the RTO or to provide new or expanded transmission service under the RTO tariffs.
We Rely on Transmission and Distribution Assets That We Do Not Own or Control to Deliver Our Wholesale Electricity. If Transmission is Disrupted, Including Our Own Transmission, or Not Operated Efficiently, or if Capacity is Inadequate, Our Ability to Sell and Deliver Power May Be Hindered
We depend on transmission and distribution facilities owned and operated by utilities and other energy companies to deliver the electricity we sell. If transmission is disrupted (as a result of weather, natural disasters or other reasons) or not operated efficiently by ISOs, in applicable markets, or if capacity is inadequate, our ability to sell and deliver products and satisfy our contractual obligations may be hindered, or we may be unable to sell products on the most favorable terms. In addition, in certain of the markets in which we operate, we may be required to pay for congestion costs if we schedule delivery of power between congestion zones during periods of high demand. If we are unable to hedge or recover for such congestion costs in retail rates, our financial results could be adversely affected.
Demand for electricity within our Utilities’ service areas could stress available transmission capacity requiring alternative routing or curtailing electricity usage that may increase operating costs or reduce revenues with adverse impacts to our results of operations. In addition, as with all utilities, potential concerns over transmission capacity could result in MISO, PJM or the FERC requiring us to upgrade or expand our transmission system, requiring additional capital expenditures.
The FERC requires wholesale electric transmission services to be offered on an open-access, non-discriminatory basis. Although these regulations are designed to encourage competition in wholesale market transactions for electricity, it is possible that fair and equal access to transmission systems will not be available or that sufficient transmission capacity will not be available to transmit electricity as we desire. We cannot predict the timing of industry changes as a result of these initiatives or the adequacy of transmission facilities in specific markets or whether independent system operators in applicable markets will operate the transmission networks, and provide related services, efficiently.
Disruptions in Our Fuel Supplies or Changes in Our Fuel Needs Could Occur, Which Could Adversely Affect Our Ability to Operate Our Generation Facilities or Impact Financial Results

We purchase fuel from a number of suppliers. The lack of availability of fuel at expected prices, or a disruption in the delivery of fuel which exceeds the duration of our on-site fuel inventories, including disruptions as a result of weather, increased transportation costs or other difficulties, labor relations or environmental or other regulations affecting our fuel suppliers, could cause an adverse impact on our ability to operate our facilities, possibly resulting in lower sales and/or higher costs and thereby adversely affect our results of operations. Operation of our coal-fired generation facilities is highly dependent on our ability to procure coal. We have long-term contracts in place for a majority of our coal and coal transportation needs. We may from time to time enter into new, or renegotiate certain of these contracts, but can provide no assurance that such contracts will be negotiated or renegotiated, as the case may be, on satisfactory terms, or at all. In addition, if prices for physical delivery are unfavorable, our financial condition, results of operations and cash flows could be materially adversely affected.

Temperature Variations as well as Weather Conditions or other Natural Disasters Could Have a Negative Impact on Our Results of Operations and Demand Significantly Below or Above Our Forecasts Could Adversely Affect Our Energy Margins
Weather conditions directly influence the demand for electric power. Demand for power generally peaks during the summer and winter months, with market prices also typically peaking at that time. Overall operating results may fluctuate based on weather conditions. In addition, we have historically sold less power, and consequently received less revenue, when weather conditions are milder. Severe weather, such as tornadoes, hurricanes, ice or snowstorms, or droughts or other natural disasters, may cause outages and property damage that may require us to incur additional costs that are generally not insured and that may not be recoverable from customers. The effect of the failure of our facilities to operate as planned under these conditions would be particularly burdensome during a peak demand period.
Customer demand could change as a result of severe weather conditions or other circumstances over which we have no control. We satisfy our electricity supply obligations through a portfolio approach of providing electricity from our generation assets, contractual relationships and market purchases. A significant increase in demand could adversely affect our energy margins if we are required to provide the energy supply to fulfill this increased demand at fixed rates, which we expect would remain below the


31


wholesale prices at which we would have to purchase the additional supply if needed or, if we had available capacity, the prices at which we could otherwise sell the additional supply. Accordingly, any significant change in demand could have a material adverse effect on our results of operations and financial position.
We Are Subject to Financial Performance Risks Related to Regional and General Economic Cycles and also Related to Heavy Manufacturing Industries such as Automotive and Steel
Our business follows economic cycles. Economic conditions are a determinant of the demand for electricity and declines in the demand for electricity will reduce our revenues. The regional economy in which our Utilities operate is influenced by conditions in automotive, steel and other heavy industries and as these conditions change, our revenues will be impacted. Additionally, the primary market areas of our Competitive Energy Services segment overlap, to a large degree, with our Utilities' territories and hence its revenues are impacted by the same economic conditions.
Increases in Customer Electric Rates and Economic Uncertainty May Lead to a Greater Amount of Uncollectible Customer Accounts
Our operations are impacted by the economic conditions in our service territories and those conditions could negatively impact the rate of delinquent customer accounts and our collections of accounts receivable which could adversely impact our financial condition, results of operations and cash flows.
We May Recognize Impairments of Recorded Goodwill or of Some of Our Long-Lived Assets, Which Would Result in Write-Offs of the Impaired Amounts
Goodwill could become impaired at one or more of our operating subsidiaries. In addition, one or more of our long-lived assets could become impaired. The actual timing and amounts of any impairments in future years would depend on many factors, including interest rates, sector market performance, our capital structure, market prices for power, results of future rate proceedings, operating and capital expenditure requirements, the value of comparable acquisitions, environmental regulations and other factors.
We Face Certain Human Resource Risks Associated with the Availability of Trained and Qualified Labor to Meet Our Future Staffing Requirements
We must find ways to balance the retention of our aging skilled workforce while recruiting new talent to mitigate losses in critical knowledge and skills due to retirements. Mitigating these risks could require additional financial commitments.
Significant Increases in Our Operation and Maintenance Expenses, Including Our Health Care and Pension Costs, Could Adversely Affect Our Future Earnings and Liquidity
We continually focus on limiting, and reducing where possible, our operation and maintenance expenses. We expect to continue to face increased cost pressures in the areas of health care and pension costs. We have experienced significant health care cost inflation in the last few years, and we expect our cash outlay for health care costs, including prescription drug coverage, to continue to increase despite measures that we have taken and expect to take requiring employees and retirees to bear a higher portion of the costs of their health care benefits. The measurement of our expected future health care and pension obligations and costs is highly dependent on a variety of assumptions, many of which relate to factors beyond our control. These assumptions include investment returns, interest rates, health care cost trends, benefit design changes, salary increases, the demographics of plan participants and regulatory requirements. If actual results differ materially from our assumptions, our costs could be significantly increased.
Our Results May be Adversely Affected by the Volatility in Pension and OPEB Expenses.
Effective in 2011, FirstEnergy elected to change its method of recognizing actuarial gains and losses of its pension and OPEB plans. This change will result in the recognition of net actuarial gains or losses, without deferral, in the fourth quarter of each year and whenever a plan is determined to qualify for a remeasurement, may result in greater volatility in pension and OPEB expenses and may materially impact our results of operations under GAAP. For additional information, see Note 1, Organization, Basis of Presentation and Significant Accounting Policies of the Combined Notes to the Consolidated Financial Statements.
Security Breaches, Including Cyber Security Breaches, and Other Disruptions Could Compromise Critical and Proprietary Information and Expose Us to Liability, Which Would Cause our Business and Reputation to Suffer.
In the ordinary course of our business, we store sensitive data, intellectual property and proprietary information regarding our business, employees, customers, suppliers and business partners in our data centers and on our networks. The secure maintenance of this information is critical to our operations. Despite security measures we have employed with respect to this information, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings and regulatory penalties. It could also disrupt our business operations and damage our reputation, which could adversely affect our business.


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Acts of War or Terrorism Could Negatively Impact Our Business
The possibility that our infrastructure, such as electric generation, transmission and distribution facilities, or that of an interconnected company, could be direct targets of, or indirect casualties of, an act of war or terrorism, could result in disruption of our ability to generate, purchase, transmit or distribute electricity. Any such disruption could result in a decrease in revenues and additional costs to purchase electricity and to replace or repair our assets, which could have a material adverse impact on our results of operations and financial condition.
Capital Improvements and Construction Projects May Not be Completed Within Forecasted Budget, Schedule or Scope Parameters
Our business plan calls for extensive capital investments. We may be exposed to the risk of substantial price increases in the costs of labor and materials used in construction. We engage numerous contractors and enter into a large number of agreements to acquire the necessary materials and/or obtain the required construction-related services. As a result, we are also exposed to the risk that these contractors and other counterparties could breach their obligations to us. Such risk could include our contractors’ inabilities to procure sufficient skilled labor as well as potential work stoppages by that labor force. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices, with resulting delays in those and other projects. Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than these mitigation provisions. This could have negative financial impacts such as incurring losses or delays in completing construction projects.
Changes in Technology May Significantly Affect Our Generation Business by Making Our Generating Facilities Less Competitive
We primarily generate electricity at large central facilities. This method results in economies of scale and lower costs than newer technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells. It is possible that advances in technologies will reduce their costs to levels that are equal to or below that of most central station electricity production, which could have a material adverse effect on our results of operations.
We May Acquire Assets That Could Present Unanticipated Issues for Our Business in the Future, Which Could Adversely Affect Our Ability to Realize Anticipated Benefits of Those Acquisitions
Asset acquisitions involve a number of risks and challenges, including: management attention; integration with existing assets; difficulty in evaluating the requirements associated with the assets prior to acquisition, operating costs, potential environmental and other liabilities, and other factors beyond our control; and an increase in our expenses and working capital requirements. Any of these factors could adversely affect our ability to achieve anticipated levels of cash flows or realize other anticipated benefits from any such asset acquisition.
Ability of Certain FirstEnergy Companies to Meet Their Obligations to or on behalf of Other FirstEnergy Companies or their Affiliates
Certain of the FirstEnergy companies have obligations to other FirstEnergy companies because of transactions involving energy, coal, other commodities, services and hedging transactions. If one FirstEnergy entity failed to perform under any of these arrangements, other FirstEnergy entities could incur losses. Their results of operations, financial position, or liquidity could be adversely affected, resulting in the nondefaulting FirstEnergy entity being unable to meet its obligations to unrelated third parties. Our hedging activities are generally undertaken with a view to overall FirstEnergy exposures. Some FirstEnergy companies may therefore be more or less hedged than if they were to engage in such transactions alone. Also, some companies affiliated with FirstEnergy also provide guarantees to third party creditors on behalf of other FirstEnergy affiliates under transactions of the type described above or under financing transactions. Any failure to perform under such a guarantee by the affiliated FirstEnergy guarantor company or under the underlying transaction by the FirstEnergy company on whose behalf the guarantee was issued could have similar adverse impacts on one or both FirstEnergy companies or their affiliates.
Energy Companies are Subject to Adverse Publicity Which Make Them Vulnerable to Negative Regulatory and Legislative Outcomes

Energy companies, including FirstEnergy's utility subsidiaries, have been the subject of criticism focused on the reliability of their distribution services and the speed with which they are able to respond to power outages, such as those caused by storm damage. Adverse publicity of this nature, or adverse publicity associated with our nuclear and/or coal-fired facilities may cause less favorable legislative and regulatory outcomes.
Our Merger with AE May Not Achieve Its Intended Results.

We entered into the merger agreement with AE with the expectation that the merger would result in various benefits, including, among other things, cost savings and operating efficiencies relating to the regulated business and the unregulated competitive business. Our ability to achieve the anticipated benefits of the merger is subject to a number of uncertainties, including whether the business and information systems of Allegheny are integrated in an efficient and effective manner. Failure to achieve these anticipated benefits could result in increased costs, decreases in the amount of expected revenues generated by us and diversion of management's time and energy and could have an adverse effect on our business, financial results and prospects. See Part II, Item 7, Management's Discussion and Analysis of Registrant and Subsidiaries for additional information.


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Risks Associated With Regulation
Complex and Changing Government Regulations, Including Those Associated With Rates Could Have a Negative Impact on Our Results of Operations
We are subject to comprehensive regulation by various federal, state and local regulatory agencies that significantly influence our operating environment. Changes in, or reinterpretations of, existing laws or regulations, or the imposition of new laws or regulations, could require us to incur additional costs or change the way we conduct our business, and therefore could have an adverse impact on our results of operations.
Our utility subsidiaries currently provide service at rates approved by one or more regulatory commissions. Thus, the rates a utility is allowed to charge may or may not be set to recover its expenses at any given time. Additionally, there may also be a delay between the timing of when costs are incurred and when costs are recovered. For example, we may be unable to timely recover the costs for our energy efficiency investments, expenses and additional capital or lost revenues resulting from the implementation of aggressive energy efficiency programs. While rate regulation is premised on providing an opportunity to earn a reasonable return on invested capital and recovery of operating expenses, there can be no assurance that the applicable regulatory commission will determine that all of our costs have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs in a timely manner.
Regulatory Changes in the Electric Industry, Including a Reversal of, Discontinuance of, or Impediment to the Present Trend Toward Competitive Markets, Could Affect Our Competitive Position and Result in Unrecoverable Costs Adversely Affecting Our Business and Results of Operations
As a result of restructuring initiatives, changes in the electric utility business have occurred, and are continuing to take place throughout the United States, including the states in which we do business. These changes have resulted, and are expected to continue to result, in fundamental alterations in the way utilities conduct their business.
Some states that have deregulated generation service have experienced difficulty in transitioning to market-based pricing. In some instances, state and federal government agencies and other interested parties have made proposals to impose rate cap extensions or otherwise impede market restructuring or even re-regulate areas of these markets that have previously been deregulated. Although we expect wholesale electricity markets to continue to be competitive, proposals to re-regulate our industry may be made, and legislative or other action affecting the electric power restructuring process may cause the process to be delayed, discontinued, restructured or reversed in the states in which we currently, or may in the future, operate. Such delays, discontinuations or reversals of electricity market restructuring in the markets in which we operate could have an adverse impact on our results of operations and financial condition.
The FERC and the U.S. Congress propose changes from time to time in the structure and conduct of the electric utility industry. If the restructuring, deregulation or re-regulation efforts result in decreased margins or unrecoverable costs, our business and results of operations would be adversely affected. We cannot predict the extent or timing of further efforts to restructure, deregulate or re-regulate our business or the industry.
The Prospect of Rising Rates Could Prompt Legislative or Regulatory Action to Restrict or Control Such Rate Increases. This In Turn Could Create Uncertainty Affecting Planning, Costs and Results of Operations and May Adversely Affect the Utilities’ Ability to Recover Their Costs, Maintain Adequate Liquidity and Address Capital Requirements
Increases in utility rates, such as may follow a period of frozen or capped rates, can generate pressure on legislators and regulators to take steps to control those increases. Such efforts can include some form of rate increase moderation, reduction or freeze. The public discourse and debate can increase uncertainty associated with the regulatory process, the level of rates and revenues, and the ability to recover costs. Such uncertainty restricts flexibility and resources, given the need to plan and ensure available financial resources. Such uncertainty also affects the costs of doing business. Such costs could ultimately reduce liquidity, as suppliers tighten payment terms, and increase costs of financing, as lenders demand increased compensation or collateral security to accept such risks.
Our Profitability is Impacted by Our Affiliated Companies’ Continued Authorization to Sell Power at Market-Based Rates
The FERC granted certain subsidiaries authority to sell electricity at market-based rates. These orders also granted them waivers of certain FERC accounting, record-keeping and reporting requirements. The FERC’s orders that grant this market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that these companies can exercise market power in transmission or generation, create barriers to entry or engage in abusive affiliate transactions. As a condition to the orders granting the generating companies market-based rate authority, every three years they are required to file a market power update to show that they continue to meet the FERC’s standards with respect to generation market power and other criteria used to evaluate whether entities qualify for market-based rates.
There Are Uncertainties Relating to Our Participation in RTOs
RTO rules could affect our ability to sell power produced by our generating facilities to users in certain markets due to transmission


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constraints and attendant congestion costs. The prices in day-ahead and real-time energy markets and RTO capacity markets have been subject to price volatility. Administrative costs imposed by RTOs, including the cost of administering energy markets, have also increased. The rules governing the various regional power markets may also change from time to time, which could affect our costs or revenues. To the degree we incur significant additional fees and increased costs to participate in an RTO, and we are limited with respect to recovery of such costs from retail customers, we may suffer financial harm. In addition, we may be allocated a portion of the cost of transmission facilities built by others due to changes in RTO transmission rate design. Finally, we may be required to expand our transmission system according to decisions made by an RTO rather than our internal planning process. As a member of an RTO, we are subject to certain additional risks, including those associated with the allocation among members of losses caused by unreimbursed defaults of other participants in that RTO’s market and those associated with complaint cases filed against the RTO that may seek refunds of revenues previously earned by its members.
Because it remains unclear which companies will be participating in the various regional power markets, or how RTOs will ultimately develop and operate, or what region they will cover, we cannot fully assess the impact that these power markets or other ongoing RTO developments may have.
Energy Conservation and Energy Price Increases Could Negatively Impact Our Financial Results
A number of regulatory and legislative bodies have introduced requirements and/or incentives to reduce energy consumption. Conservation programs could impact our financial results in different ways. To the extent conservation resulted in reduced energy demand or significantly slowed the growth in demand, the value of our competitive generation and other unregulated business activities could be adversely impacted. We currently have energy efficiency riders in place to recover the cost of these programs either at or near a current recovery timeframe in the states we operate. In New Jersey, we recover the costs for energy efficiency programs through the SBC. Currently only Ohio has provisions for recovery of lost revenues. In our regulated operations, conservation could negatively impact us depending on the regulatory treatment of the associated impacts. Should we be required to invest in conservation measures that result in reduced sales from effective conservation, regulatory lag in adjusting rates for the impact of these measures could have a negative financial impact. We could also be impacted if any future energy price increases result in a decrease in customer usage. Our results could be affected if we are unable to increase our customer’s participation in our energy efficiency programs. We are unable to determine what impact, if any, conservation and increases in energy prices will have on our financial condition or results of operations.
Our Business and Activities are Subject to Extensive Environmental Requirements and Could be Adversely Affected by such Requirements
We plan to retire nine older coal-fired generating plants by September 1, 2012, as a result of a comprehensive review of FirstEnergy's coal-fired generating facilities in light of the MATS rules that were recently finalized and other environmental requirements. We may be forced to shut down other facilities, either temporarily or permanently, if we are unable to comply with certain environmental requirements, or if we make a determination that the expenditures required to comply with such requirements are uneconomical.
The EPA is Conducting NSR Investigations at a Number of Generating Plants that We Currently or Formerly Owned, the Results of Which Could Negatively Impact Our Results of Operations and Financial Condition
We may be subject to risks in connection with changing or conflicting interpretations of existing laws and regulations, including, for example, the applicability of EPA's NSR programs . Under the CAA, modification of our generation facilities in a manner that results in increased emissions could subject our existing facilities to the far more stringent NSR standards applicable to new facilities.
The EPA has taken the view that many companies, including many energy producers, have been modifying emissions sources in violation of NSR standards in connection with work considered by the companies to be routine maintenance. We are currently involved in litigation and EPA investigations concerning alleged violations of the NSR standards at certain of our existing and former generating facilities. We intend to vigorously pursue and defend our position but we are unable to predict their outcomes. If NSR and similar requirements are imposed on our generation facilities, in addition to the possible imposition of fines, compliance could entail significant capital investments in pollution control technology, which could have an adverse impact on our business, results of operations, cash flows and financial condition. For a more complete discussion see Note 16, Commitments, Guarantees and Contingencies - Environmental Matters of the Combined Notes to the Consolidated Financial Statements.
Costs of Compliance with Environmental Laws are Significant, and the Cost of Compliance with Future Environmental Laws, Including Limitations on GHGEmissions, Could Adversely Affect Cash Flow and Profitability

Our operations are subject to extensive federal, state and local environmental statutes, rules and regulations. Compliance with these legal requirements requires us to incur costs for among other things, installation and operation of pollution control equipment, emission monitoring and fees, remediation and permitting at our facilities. These expenditures have been significant in the past and may increase in the future. If the cost of compliance with existing environmental laws and regulations does increase, it could adversely affect our business and results of operations, financial position and cash flows. Moreover, new environmental laws or regulations or changes to existing environmental laws or regulations may materially increase our costs of compliance or accelerate the timing of capital expenditures. Because of the deregulation of generation, we may not directly recover through rates additional costs incurred for such compliance. Our compliance strategy, although reasonably based on available information, may not successfully address future relevant standards and interpretations. If we fail to comply with environmental laws and regulations or


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new interpretations of longstanding requirements, even if caused by factors beyond our control, that failure could result in the assessment of civil or criminal liability and fines. In addition, any alleged violation of environmental laws and regulations may require us to expend significant resources to defend against any such alleged violations.

There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. Environmental advocacy groups, other organizations and some agencies in the United States and elsewhere are focusing considerable attention on carbon dioxide emissions from power generation facilities and their potential role in climate change. There is a growing consensus in the United States and globally that GHG emissions are a major cause of global warming and that some form of regulation will be forthcoming at the federal level with respect to GHG emissions (including CO2) and such regulation could result in the creation of substantial additional costs in the form of taxes or emission allowances. As a result, it is possible that state and federal regulations will be developed that will impose more stringent limitations on emissions than are currently in effect. Due to the uncertainty of control technologies available to reduce GHG emissions, including CO2, as well as the unknown nature of potential compliance obligations should climate change regulations be enacted, we cannot provide any assurance regarding the potential impacts these future regulations would have on our operations. In addition, any legal obligation that would require us to substantially reduce our emissions could require extensive mitigation efforts and, in the case of carbon dioxide legislation, would raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities. Until specific regulations are issued, the impact that any new environmental regulations, voluntary compliance guidelines, enforcement initiatives, or legislation may have on our results of operations, financial condition or liquidity is not determinable.

FirstEnergy cannot currently estimate the financial impact of certain environmental laws or initiatives including climate change policies, but 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. See Note 16, Commitments, Guarantees and Contingencies - Environmental Matters of the Combined Notes to the Consolidated Financial Statements for a more detailed discussion of the federal, state and international initiatives seeking to reduce emissions of GHG.

We Could be Exposed to Private Rights of Action Seeking Damages Under Various State and Federal Law Theories

Claims have been made against certain energy companies alleging that CO2 emissions from power generating facilities constitute a public nuisance under federal and/or state common law. As a result, private individuals may seek to enforce environmental laws and regulations against us and could allege personal injury or property damages. While FirstEnergy is not a party to this litigation, it, and/or one of its subsidiaries, could be named in actions making similar allegations. An unfavorable ruling in any such case could have an adverse impact on our results of operations and financial condition and could significantly impact our operations.

Our Costs to Comply with Various Recently Adopted EPA Emission Regulations Could be Substantial and Result in Significant Changes to Our Operations

We are required to comply with recently adopted emission regulations. The EPA's CAIR and CSAPR require reductions of NOx and SO2 emissions in two phases, ultimately capping SO2 and NOx emissions in affected states. In July 2011, the EPA finalized the CSAPR (which was stayed in December 2011 pending a decision on various legal challenges) to replace CAIR, which remains in effect until CSAPR becomes effective.

Depending on the outcome of these legal proceedings and how any final rules are ultimately implemented, MP's, FGCO's and AE Supply's future cost of compliance may be substantial and changes to FirstEnergy's operations may result.

Additionally, on December 21, 2011, the EPA finalized the MATS to establish emission standards for, among other things, mercury, hydrochloric acid and various metals for electric generating units. The costs associated with MATS, and other environmental laws, is substantial and led to the Company's recent announcement to retire nine older coal-fired generating units. Depending on how the CSPAR and MATS are ultimately implemented, FirstEnergy's future cost of compliance with such regulations may be substantial and additional changes to FirstEnergy's operations may result. See Note 16, Commitments, Guarantees and Contingencies - Environmental Matters of the Combined Notes to the Consolidated Financial Statements for a more detailed discussion of the above-referenced EPA regulations.

Various Federal and State Water Quality Regulations May Require Us to Make Material Capital Expenditures

The EPA established performance standards under the Clean Water Act which requires the EPA to establish performance standards for reducing impacts on fish and shellfish from cooling water intake structures at certain existing electric generating plants, specifically, impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). In 2011, the EPA proposed new regulations under the Clean Water Act which generally require fish impingement to be reduced to a 12% annual average and calls for studies to be conducted at the majority of our existing generating facilities to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic life. FirstEnergy is studying the cost and effectiveness of various control options to divert fish away from its plants' cooling water intake system. Depending on the results of such studies and the EPA's further rulemaking and any final action taken by the states, the future costs of compliance with these standards may require material capital expenditures. See Note 16, Commitments, Guarantees and Contingencies - Environmental Matters of the Combined Notes to the Consolidated Financial Statements for a more detailed discussion of the various federal and state water


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quality regulations listed above.

Compliance with any Coal Combustion Residual Regulations Could Have an Adverse Impact on Our Results of Operations and Financial Condition

We are subject to various federal and state hazardous waste regulations. The EPA has requested comments from the states on options for regulating coal combustion residuals, including whether they should be regulated as hazardous or non-hazardous waste.

The EPA asserted that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry and has proposed two options for additional regulation of coal combustion residuals, including the option of regulation as a special waste under the EPA's hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. FirstEnergy's future cost of compliance with any coal combustion residuals regulations that may be issued could be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the EPA or the states. Compliance with those regulations could have an adverse impact on our results of operations and financial condition.
Remediation of Environmental Contamination at Current or Formerly Owned Facilities
We are subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we may have generated regardless of whether the liabilities arose before, during or after the time we owned or operated the facilities. Remediation activities associated with our former MGP operations are one source of such costs. We are currently involved in a number of proceedings relating to sites where other hazardous substances have been deposited and may be subject to additional proceedings in the future. We also have current or previous ownership interests in sites associated with the production of gas and the production and delivery of electricity for which we may be liable for additional costs related to investigation, remediation and monitoring of these sites. Citizen groups or others may bring litigation over environmental issues including claims of various types, such as property damage, personal injury, and citizen challenges to compliance decisions on the enforcement of environmental requirements, such as opacity and other air quality standards, which could subject us to penalties, injunctive relief and the cost of litigation. We cannot predict the amount and timing of all future expenditures (including the potential or magnitude of fines or penalties) related to such environmental matters, although we expect that they could be material.
In some cases, a third party who has acquired assets from us has assumed the liability we may otherwise have for environmental matters related to the transferred property. If the transferee fails to discharge the assumed liability or disputes its responsibility, a regulatory authority or injured person could attempt to hold us responsible, and our remedies against the transferee may be limited by the financial resources of the transferee.
We Are and May Become Subject to Legal Claims Arising from the Presence of Asbestos or Other Regulated Substances at Some of Our Facilities
We have been named as a defendant in pending asbestos litigation involving multiple plaintiffs and multiple defendants. In addition, asbestos and other regulated substances are, and may continue to be, present at our facilities where suitable alternative materials are not available. We believe that any remaining asbestos at our facilities is contained. The continued presence of asbestos and other regulated substances at these facilities, however, could result in additional actions being brought against us.
Availability and Cost of Emission Allowances Could Negatively Impact Our Costs of Operations

Although recent court rulings and current conditions have reduced the immediate risk of a negative impact on our operating costs, the uncertainty around CAA programs and requirements continue to be a major concern. We are still required to maintain, either by allocation or purchase, sufficient emission allowances to support our operations in the ordinary course of operating our power generation facilities. These allowances are used to meet our obligations imposed by various applicable environmental laws. If our operational needs require more than our allocated allowances, we may be forced to purchase such allowances on the open market, which could be costly. If we are unable to maintain sufficient emission allowances to match our operational needs, we may have to curtail our operations so as not to exceed our available emission allowances, or install costly new emissions controls. As we use the emissions allowances that we have purchased on the open market, costs associated with such purchases will be recognized as operating expense. If such allowances are available for purchase, but only at significantly higher prices, the purchase of such allowances could materially increase our costs of operations in the affected markets.
Mandatory Renewable Portfolio Requirements Could Negatively Affect Our Costs
If federal or state legislation mandates the use of renewable and alternative fuel sources, such as wind, solar, biomass and geothermal and such legislation would not also provide for adequate cost recovery, it could result in significant changes in our business, including renewable energy credit purchase costs, purchased power and potentially renewable energy credit costs and capital expenditures. We are unable to predict what impact, if any, these changes may have on our financial condition or results of operations.
The Continuing Availability and Operation of Generating Units is Dependent on Retaining or Renewing the Necessary Licenses, Permits, and Operating Authority from Governmental Entities, Including the NRC


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We are required to have numerous permits, approvals and certificates from the agencies that regulate our business. We believe the necessary permits, approvals and certificates have been obtained for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from future regulatory activities of any of these agencies and we are not assured that any such permits, approvals or certifications will be renewed.
Potential NRC Regulation in Response to the Incident at Japan's Fukushima Daiichi Nuclear Plant Could Adversely Effect Our Business and Financial Condition

As a result of the NRC's investigation of the incident at the Fukushima Daiichi nuclear plant, potential exists for the NRC to promulgate new or revised requirements with respect to nuclear plants located in the United States, which could necessitate additional expenditures at our nuclear plants. For example, as a follow up to the NRC near-term Task Force's review and analysis of the Fukushima Daiichi accident, in January 2012, the NRC released an updated seismic risk model that plant operators must use in performing the seismic reevaluations recommended by the task force. These reevaluations could result in the required implementation of additional mitigation strategies or modifications. It is also possible that the NRC could suspend or otherwise delay pending nuclear relicensing proceedings, including the Davis-Besse relicensing proceeding. The impact of any such regulatory actions could adversely affect FirstEnergy's financial condition or results of operations.
The Physical Risks Associated with Climate Change May Impact Our Results of Operations and Cash Flows
Physical risks of climate change, such as more frequent or more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, and other related phenomena, could affect some, or all, of our operations. Severe weather or other natural disasters could be destructive, which could result in increased costs, including supply chain costs. An extreme weather event within the Utilities' service areas can also directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment. Finally, climate change could affect the availability of a secure and economical supply of water in some locations, which is essential for continued operation of generating plants.
Future Changes in Accounting Standards May Affect Our Reported Financial Results
The SEC, FASB or other authoritative bodies or governmental entities may issue new pronouncements or new interpretations of existing accounting standards that may require us to change our accounting policies. These changes are beyond our control, can be difficult to predict and could materially impact how we report our financial condition and results of operations. We could be required to apply a new or revised standard retroactively, which could adversely affect our financial position. The SEC announced a work plan to aid in its evaluation of the impact that the use of IFRS by U.S. public companies would have on the U.S. securities market and has identified several potential options to incorporate IFRS in the United States. The SEC expects to announce a more specific course of action in 2012. We continue to monitor the development of the potential implementation of IFRS.
Increases in Taxes and Fees May Adversely Effect Our Results of Operation, Financial Audit and Cash Flow
Due to the revenue needs of the United States and the states and jurisdictions in which we operate, various tax and fee increases may be proposed or considered. We cannot predict whether legislation or regulation will be introduced, the form of any legislation or regulation, whether any such legislation or regulation will be passed by legislatures or regulatory bodies. If enacted, these changes could increase tax costs and could have a negative impact on our results of operations, financial condition and cash flows.
Risks Associated With Financing and Capital Structure
Disruptions in the Capital and Credit Markets May Adversely Affect Our Business, Including the Availability and Cost of Short-Term Funds for Liquidity Requirements, Our Ability to Meet Long-Term Commitments, Our Ability to Hedge Effectively Our Generation Portfolio, and the Competitiveness and Liquidity of Energy Markets; Each Could Adversely Affect Our Results of Operations, Cash Flows and Financial Condition
We rely on the capital markets to meet our financial commitments and short-term liquidity needs if internal funds are not available from our operations. We also use letters of credit provided by various financial institutions to support our hedging operations. Disruptions in the capital and credit markets could adversely affect our ability to draw on our respective credit facilities. Our access to funds under those credit facilities is dependent on the ability of the financial institutions that are parties to the facilities to meet their funding commitments. Those institutions may not be able to meet their funding commitments if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests within a short period of time.
Longer-term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant financial institutions could adversely affect our access to liquidity needed for our business. Any disruption could require us to take measures to conserve cash until the markets stabilize or until alternative credit arrangements or other funding for our business needs can be arranged. Such measures could include deferring capital expenditures, changing hedging strategies to reduce collateral-posting requirements, and reducing or eliminating future dividend payments or other discretionary uses of cash.
The strength and depth of competition in energy markets depends heavily on active participation by multiple counterparties, which


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could be adversely affected by disruptions in the capital and credit markets. Reduced capital and liquidity and failures of significant institutions that participate in the energy markets could diminish the liquidity and competitiveness of energy markets that are important to our business. Perceived weaknesses in the competitive strength of the energy markets could lead to pressures for greater regulation of those markets or attempts to replace those market structures with other mechanisms for the sale of power, including the requirement of long-term contracts, which could have a material adverse effect on our results of operations and cash flows.
Interest Rates and/or a Credit Rating Downgrade Could Negatively Affect Our Financing Costs, Our Ability to Access Capital and Our Requirement to Post Collateral
We have near-term exposure to interest rates from outstanding indebtedness indexed to variable interest rates, and we have exposure to future interest rates to the extent we seek to raise debt in the capital markets to meet maturing debt obligations and fund construction or other investment opportunities. Past disruptions in capital and credit markets have resulted in higher interest rates on new publicly issued debt securities, increased costs for certain of our variable interest rate debt securities and failed remarketings of variable interest rate tax-exempt debt issued to finance certain of our facilities. Similar future disruptions could increase our financing costs and adversely affect our results of operations. Also, interest rates could change as a result of economic or other events that our risk management processes were not established to address. As a result, we cannot always predict the impact that our risk management decisions may have on us if actual events lead to greater losses or costs than our risk management positions were intended to hedge. Although we employ risk management techniques to hedge against interest rate volatility, significant and sustained increases in market interest rates could materially increase our financing costs and negatively impact our reported results of operations.
We rely on access to bank and capital markets as sources of liquidity for cash requirements not satisfied by cash from operations. A downgrade in our credit ratings from the nationally recognized credit rating agencies, particularly to a level below investment grade, could negatively affect our ability to access the bank and capital markets, especially in a time of uncertainty in either of those markets, and may require us to post cash collateral to support outstanding commodity positions in the wholesale market, as well as available letters of credit and other guarantees. Furthermore, a downgrade could increase the cost of such capital by causing us to incur higher interest rates and fees associated with such capital. A rating downgrade would also increase the fees we pay on our various existing credit facilities, thus increasing the cost of our working capital. A rating downgrade could also impact our ability to grow our businesses by substantially increasing the cost of, or limiting access to, capital. See Note 16, Commitments, Guarantees and Contingencies - Guarantees and Other Assurances of the Combined Notes to the Consolidated Financial Statements for more information associated with a credit ratings downgrade leading to the posting of cash collateral.
The Soundness of Financial Institutions or Counterparties Could Adversely Affect Us
We have exposure to many different domestic and foreign financial institutions and counterparties and we routinely execute transactions with counterparties in connection with our hedging activities, including brokers and dealers, commercial banks, investment banks and other institutions and industry participants. Many of these transactions expose us to credit risk in the event that any of our lenders or counterparties are unable to honor their commitments or otherwise default under a financing agreement. We also deposit cash balances in short-term investments. Our ability to access our cash quickly depends on the soundness of the financial institutions in which those funds reside. Any delay in our ability to access those funds, even for a short period of time, could have a material adverse effect on our results of operations and financial condition.
We Must Rely on Cash from Our Subsidiaries and Any Restrictions on Our Utility Subsidiaries' Ability to Pay Dividends or Make Cash Payments to Us May Adversely Affect Our Financial Condition
We are a holding company and our investments in our subsidiaries are our primary assets. Substantially all of our business is conducted by our subsidiaries. Consequently, our cash flow is dependent on the operating cash flows of our subsidiaries and their ability to upstream cash to the holding company. Our utility subsidiaries are regulated by various state utility commissions that generally possess broad powers to ensure that the needs of utility customers are being met. Those state commissions could attempt to impose restrictions on the ability of our utility subsidiaries to pay dividends or otherwise restrict cash payments to us.
We Cannot Assure Common Shareholders that Future Dividend Payments Will be Made, or if Made, in What Amounts they May be Paid

Our Board of Directors regularly evaluates our common stock dividend policy and determines the dividend rate each quarter. The level of dividends will continue to be influenced by many factors, including, among other things, our earnings, financial condition and cash flows from subsidiaries, as well as general economic and competitive conditions. We cannot assure common shareholders that dividends will be paid in the future, or that, if paid, dividends will be at the same amount or with the same frequency as in the past.
ITEM 1B.UNRESOLVED STAFF COMMENTS
None.


39


ITEM 2.PROPERTIES
The Ohio Companies', Penn's, FGCO’s and NGC’s respective first mortgage indentures constitute direct first liens on substantially all of the respective physical property, subject only to excepted encumbrances, as defined in the first mortgage indentures. See Notes 6, Leases, and 12, Capitalization of the Combined Notes to the Consolidated Financial Statements for information concerning leases and financing encumbrances affecting certain of the Utilities’, FGCO’s and NGC’s properties.
FirstEnergy controls the following generation sources as of January 31, 2012, shown in the table below. Except for the leasehold interests, OVEC participation and wind power arrangements referenced in the footnotes to the table, substantially all FES' competitive generating units are owned by NGC (nuclear) and FGCO (non-nuclear); the regulated generating units are owned by JCP&L and MP.


40


      Competitive  
Plant (Location) Unit Total FES AE Supply Regulated
    Net Demonstrated Capacity (MW)
Super-critical Coal-fired:  
        
Bruce Mansfield (Shippingport, PA) 1
 830
(1) 
830
 —
 —
Bruce Mansfield (Shippingport, PA) 2
 830
(2) 
830
 —
 —
Bruce Mansfield (Shippingport, PA) 3
 830
(3) 
830
 —
 —
Harrison (Haywood, WV) 1-3
 1,984
 —
 1,576
 408
Hatfield's Ferry (Masontown, PA) 1-3
 1,710
 —
 1,710
 —
Pleasants (Willow Island, WV) 1-2
 1,300
 —
 1,200
 100
W. H. Sammis (Stratton, OH) 6-7
 1,200
  
1,200
 —
 —
Fort Martin (Maidsville, WV) 1-2
 1,107
 —
 —
 1,107
Eastlake (Eastlake, OH)(4)
 5
 597
 597
 —
 —
    10,388
 4,287
 4,486
 1,615
Sub-critical and Other Coal-fired:          
W. H. Sammis (Stratton, OH) 1-5
 1,020
  
1,020
 —
 —
Eastlake (Eastlake, OH)(4)
 1-4
 636
 636
 —
 —
Bay Shore (Toledo, OH) 1
 136
 136
    
Bay Shore (Toledo, OH)(4)
 2-4
 495
 495
 —
 —
Armstrong (Adrian, PA)(4)
 1-2
 356
 —
 356
 —
Albright (Albright, WV)(4)
 1-3
 292
 —
 —
 292
Mitchell (Courtney, PA) 3
 288
 —
 288
 —
Lakeshore (Cleveland, OH)(4)
 18
 245
 245
 —
 —
Ashtabula (Ashtabula, OH)(4)
 5
 244
 244
 —
 —
Willow Island (Willow Island, WV)(4)
 1-2
 242
 —
 —
 242
Rivesville (Rivesville, WV)(4)
 5-6
 126
 —
 —
 126
R. Paul Smith (Williamsport, MD)(4)
 3-4
 116
 —
 116
 —
R. E. Burger (Shadyside, OH) 3
 94
 94
 —
 —
OVEC (Cheshire, OH) (Madison, IN) 1-11
 188
(5) 
110
 67
 11
   
 4,478
  
2,980
 827
 671
Nuclear:  
  
  
     
Beaver Valley (Shippingport, PA) 1
 911
  
911
 —
 —
Beaver Valley (Shippingport, PA) 2
 904
(6) 
904
 —
 —
Davis-Besse (Oak Harbor, OH) 1
 908
  
908
 —
 —
Perry (N. Perry Village, OH) 1
 1,268
(7) 
1,268
 —
 —
   
 3,991
  
3,991
 —
 —
Gas/Oil-fired:  
  
  
     
AE Nos. 1, 2, 3, 4 & 5 (Springdale, PA) 1-5
 638
 —
 638
 —
West Lorain (Lorain, OH) 1-6
 545
  
—
 545
 —
AE Nos. 12 & 13 (Chambersburg, PA) 12-13
 88
 —
 88
 —
AE Nos. 8 & 9 (Gans, PA) 8-9
 88
 —
 88
 —
Mitchell (Courtney, PA) 2
 82
 —
 82
 —
Hunlock CT (Hunlock Creek, PA) 1
 45
 —
 45
 —
Buchanan (Oakwood, VA) 1-2
 43
(8) 
—
 43
 —
Other   216
 216
 —
 —
    1,745
 216
 1,529
 —
Pumped-storage and Hydro:  
  
  
     
Bath County (Warm Springs, VA) 1-6
 1,110
(9) 
—
 660
 450
Seneca (Warren, PA) 1-3
 451
  
451
 —
 —
Yard’s Creek (Blairstown Twp., NJ) 1-3
 200
(10) 
—
 —
 200
Lake Lynn (Lake Lynn, PA) 1-4
 52
(11) 
—
 52
  
Other   19
 —
 19
 —
    1,832
 451
 731
 650
Wind Power  
 376
(12) 
376
 —
 —
Total   22,810
 12,301
 7,573
 2,936


41


(1)
Includes FGCO’s leasehold interest of 93.825% (779 MW) and CEI’s leasehold interest of 6.175% (51 MW), which has been assigned to FGCO.
(2)
Includes CEI’s and TE’s leasehold interests of 27.17% (226 MW) and 16.435% (136 MW), respectively, which have been assigned to FGCO.
(3)
Includes CEI’s and TE’s leasehold interests of 23.247% (193 MW) and 18.915% (157 MW), respectively, which have been assigned to FGCO.
(4)
During the first quarter of 2012, FirstEnergy announced that these coal-fired plants will be retired by September 1, 2012, subject to review for reliability impacts by PJM.
(5)
Represents FGCO’s 4.85% and AE's 3.5% entitlement based on their participation in OVEC.
(6)
Includes OE’s leasehold interest of 16.65% (151 MW) from non-affiliates.
(7)
Includes OE’s leasehold interest of 8.11% (103 MW) from non-affiliates.
(8)
Buchanan Energy is a subsidiary of AE Supply. CNX Gas Corporation and Buchanan Energy have equal ownership interests in Buchanan Generation, LLC. AE Supply operates and dispatches 100% of Buchanan Generation, LLC's 86 MWs.
(9)
Represents capacity entitlement through ownership of AGC.
(10)
Represents JCP&L’s 50% ownership interest.
(11)
AE Supply has a license for Lake Lynn through 2024.
(12)
Includes 167 MW from leased facilities and 209 MW under power purchase agreements.
The above generating plants and load centers are connected by a transmission system consisting of elements having various voltage ratings ranging from 23 kV to 500 kV. The Utilities’ overhead and underground transmission lines aggregate 24,305 pole miles.
The Utilities’ electric distribution systems include 254,899 miles of overhead pole line and underground conduit carrying primary, secondary and street lighting circuits. They own substations with a total installed transformer capacity of approximately 140,158,000 kV-amperes.
All of FirstEnergy's generation, transmission and distribution assets operate in PJM.
FirstEnergy’s distribution and transmission systems as of December 31, 2011, consist of the following:
 
Distribution
Lines(1)
 
Transmission
Lines(1)
 
Substation
Transformer
Capacity(2)
   kV Amperes
OE62,238
 461
 7,763,000
Penn13,419
 52
 1,425,000
CEI33,252
 —
 8,938,000
TE17,593
 81
 3,040,000
JCP&L22,800
 2,550
 23,150,000
Met-Ed18,695
 1,406
 10,819,000
Penelec27,131
 2,909
 15,234,000
ATSI(3)
—
 7,524
 23,578,000
WP20,026
 4,419
 14,077,000
MP20,730
 2,625
 15,230,000
PE19,015
 2,126
 11,033,000
TrAIL(4)
—
 152
 5,871,000
Total254,899
 24,305
 140,158,000
(1)
Pole miles
(2)
Top rating of in-service power transformers only. Excludes grounding banks, station power transformers, and generator and customer-owned transformers.
(3)
Represents transmission lines of 69kV and above located in the service areas of OE, Penn, CEI and TE.
(4)
Represents transmission lines at 500kV located in the service areas of MP, PE and WP.
ITEM 3.LEGAL PROCEEDINGS
Reference is made to Note 16, Commitments, Guarantees and Contingencies of the Combined Notes to the Consolidated Financial Statements for a description of certain legal proceedings involving FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec.
ITEM 4.MINE SAFETY DISCLOSURE
Signal Peak Mine Safety
During 2011, FirstEnergy, through its FEV wholly owned subsidiary, held a 50% interest in Global Mining Group, LLC, a joint venture owning Signal Peak, which is a company that constructed and operates the Bull Mountain Mine No. 1 (Mine), an underground coal mine near Roundup Montana. The operation of the Mine is subject to regulation by the MSHA under the Mine Act.


42


On October 18, 2011, FirstEnergy announced that Gunvor Group, Ltd. signed an agreement to purchase a one-third interest in the Signal Peak coal mine in Montana. As a result of the sale, FirstEnergy, through its wholly owned subsidiary, FEV, currently has a 33-1/3% interest in Global Holding, a joint venture that owns Signal Peak.
Information concerning mine safety violations or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act is included in Exhibit 95 to this Annual Report on Form 10-K.
PART II
ITEM 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
The information required by Item 5 regarding FirstEnergy’s market information, including stock exchange listings and quarterly stock market prices, dividends and holders of common stock is included in Item 6.
Information for FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec is not disclosed because they are wholly owned subsidiaries of FirstEnergy and there is no market for their common stock.
Information regarding compensation plans for which shares of FirstEnergy common stock may be issued is incorporated herein by reference to FirstEnergy’s 2012 proxy statement to be filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.
The table below includes information on a monthly basis regarding purchases made by FE of its common stock during the fourth quarter of 2011.
  Period
  October November December Fourth Quarter
Total Number of Shares Purchased(1)
 112,225
 167,674
 712,539
 992,438
Average Price Paid per Share $44.36
 $44.32
 $44.19
 $44.23
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 —
 —
 —
 —
(1)
Share amounts reflect purchases on the open market to satisfy FirstEnergy's obligations to deliver common stock for some or all of the following: 2007 Incentive Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan, Director Compensation, Allegheny Energy, Inc. 1998 Long-Term Incentive Plan, Allegheny Energy, Inc. 2008 Long-Term Incentive Plan, Allegheny Energy, Inc, Non-Employee Director Stock Plan, Allegheny Energy, Inc, Amended and Restated Revised Plan for Deferral of Compensation of Directors, and Stock Investment Plan.
ITEM 6.SELECTED FINANCIAL DATA
For the Years Ended December 31, 2011 
2010(1)
 
2009(1)
 
2008(1)
 
2007(1)
  (In millions, except per share amounts)
Revenues $16,258
 $13,339
 $12,973
 $13,627
 $12,802
Earnings Available to FirstEnergy Corp.(2)
 $885
 $742
 $872
 $623
 $1,489
Earnings per Share of Common Stock:(2)
          
Basic $2.22
 $2.44
 $2.87
 $2.05
 $4.86
Diluted $2.21
 $2.42
 $2.85
 $2.03
 $4.80
Weighted Average Shares Outstanding:          
Basic 399
 304
 304
 304
 306
Diluted 401
 305
 306
 307
 310
Dividends Declared per Share of Common Stock(3)
 $2.20
 $2.20
 $2.20
 $2.20
 $2.05
Total Assets(4)
 $47,326
 $35,531
 $35,054
 $34,206
 $32,394
Capitalization as of December 31:          
Total Equity(5)
 $13,299
 $8,952
 $9,014
 $8,748
 $9,129
Long-Term Debt and Other Long-Term Obligations 15,716
 12,579
 12,008
 9,100
 8,869
Total Capitalization(5)
 $29,015
 $21,531
 $21,022
 $17,848
 $17,998
(1)
Reflects the retrospective change in recognizing pensions and OPEB costs.
(2)
The retrospective change in accounting for pensions and OPEB costs decreased Earnings Available to FirstEnergy Corp and Earnings Per Share (basic; diluted) as follows: 2010 - $42 million ($0.14; $0.15 per share), 2009 - $134 million ($0.44; $0.44 per share) and 2008 - $719


43


million ($2.36; $2.35 per share); and increased Earnings Available to FirstEnergy Corp. and Earnings Per Share (basic; diluted) in 2007 by $180 million ($0.59; $0.58 per share).
(3)
Dividends declared in 2011, 2010, 2009 and 2008 include four quarterly dividends of $0.55 per share. Dividends declared in 2007 include three quarterly payments of $0.50 per share in 2007 and one quarterly payment of $0.55 per share in 2008.
(4)
The retrospective change in accounting for pensions and OPEB costs increased Total Assets as of December 31 as follows: 2010 - $726 million, 2009 - $750 million, 2008 - $685 million and 2007 - $83 million.
(5)
The retrospective change in accounting for pensions and OPEB costs increased Total Equity as of December 31 as follows: 2010 - $439 million, 2009 - $457 million, 2008 - $433 million and 2007 - $122 million.
PRICE RANGE OF COMMON STOCK
The common stock of FirstEnergy Corp. is listed on the New York Stock Exchange under the symbol “FE” and is traded on other registered exchanges.
 2011 2010
 High Low High Low
First Quarter$40.80
 $36.11
 $47.09
 $38.31
Second Quarter$45.80
 $36.50
 $39.96
 $33.57
Third Quarter$46.51
 $38.77
 $39.06
 $34.51
Fourth Quarter$46.10
 $41.55
 $40.12
 $35.00
Yearly$46.51
 $36.11
 $47.09
 $33.57
Prices are from http://finance.yahoo.com.
SHAREHOLDER RETURN
The following graph shows the total cumulative return from a $100 investment on December 31, 2006 in FirstEnergy’s common stock compared with the total cumulative returns of EEI’s Index of Investor-Owned Electric Utility Companies and the S&P 500.
HOLDERS OF COMMON STOCK
There were 115,120 and 114,808 holders of 418,216,437 shares of FirstEnergy’s common stock as of December 31, 2011 and January 31, 2012, respectively. Information regarding retained earnings available for payment of cash dividends is given in Note 12, Capitalization of the Combined Notes to the Consolidated Financial Statements.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.


44


ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT AND SUBSIDIARIES

Forward-Looking Statements: This Form 10-K 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.
The impact of the regulatory process on the pending matters before FERC in the various states in which we do business including, but not limited to, matters related to rates.
The status of the PATH project in light of PJM's direction to suspend work on the project pending review of its planning process, its re-evaluation of the need for the project and the uncertainty of the timing and amounts of any related capital expenditures.
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.
Financial derivative reforms that could increase our liquidity needs and collateral costs.
The continued ability of FirstEnergy's regulated utilities to collect transition and other costs.
Operation and maintenance costs being higher than anticipated.
Other legislative and regulatory changes, and revised environmental requirements, including possible GHG emission, water intake and coal combustion residual regulations, the potential impacts of any laws, rules or regulations that ultimately replace CAIR, including CSAPR which was stayed by the courts on December 30, 2011, and the effects of the EPA's MATS rules.
The uncertainty of the timing and amounts of the capital expenditures that may arise in connection with litigation, including NSR litigation or potential regulatory initiatives or rulemakings (including that such expenditures could result in our decision to shut down or idle certain generating units).
The uncertainty associated with the company's plan to retire its older unscrubbed regulated and competitive fossil units, including the impact on vendor commitments and PJM's review of the company's plans.
Adverse regulatory or legal decisions and outcomes with respect to our nuclear operations (including, but not limited to the revocation or non-renewal of necessary licenses, approvals or operating permits by the NRC including as a result of the incident at Japan's Fukushima Daiichi Nuclear Plant).
Issues that could result from our continuing investigation and analysis of the indications of cracking in the plant shield building at Davis-Besse.
Adverse legal decisions and outcomes related to Met-Ed's and Penelec's ability to recover certain transmission costs through their transmission service charge riders.
The continuing availability of generating units and changes in their ability to operate at or near full capacity.
Replacement power costs being higher than anticipated or inadequately hedged.
The ability to comply with applicable state and federal reliability standards and energy efficiency mandates.
Changes in customers' demand for power, including but not limited to, changes resulting from the implementation of state and federal energy efficiency mandates.
The ability to accomplish or realize anticipated benefits from strategic goals.
FirstEnergy's ability to improve electric commodity margins and the impact of, among other factors, the increased cost of coal and coal transportation on such margins.
The ability to experience growth in the distribution business.
The changing market conditions that could affect the value of assets held in FirstEnergy's NDTs, pension trusts and other trust funds, and cause FirstEnergy and its subsidiaries to make additional contributions sooner, or in amounts that are larger than currently anticipated.
The impact of changes to material accounting policies.
The ability to access the public securities and other capital and credit markets in accordance with FirstEnergy's financing plan, the cost of such capital and overall condition of the capital and credit markets affecting FirstEnergy and its subsidiaries.
Changes in general economic conditions affecting FirstEnergy and its subsidiaries.
Interest rates and any actions taken by credit rating agencies that could negatively affect FirstEnergy's and its subsidiaries' access to financing or their costs of financings and increase requirements to post additional collateral to support outstanding commodity positions, LOCs and other financial guarantees.
The continuing uncertainty of the national and regional economy and its impact on major industrial and commercial customers of FirstEnergy and its subsidiaries.
Issues concerning the soundness of financial institutions and counterparties with which FirstEnergy and its subsidiaries do business.
Issues arising from the completed merger of FirstEnergy and AE and the ongoing coordination of their combined operations


45


including FirstEnergy's ability to maintain relationships with customers, employees or suppliers, as well as the ability to continue to successfully integrate the businesses and realize cost savings and any other synergies .
The risks and other factors discussed from time to time in FirstEnergy's and its applicable subsidiaries' SEC filings, and other similar factors.

Dividends declared from time to time on FE's common stock during any annual period may in the aggregate vary from the indicated amount due to circumstances considered by FE's Board of Directors at the time of the actual declarations. A security rating is not a recommendation to buy or hold securities and is subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.
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 FirstEnergy's 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. The registrants expressly disclaim any current intention to update, except as required by law, any forward-looking statements contained herein as a result of new information, future events or otherwise.
See Item 1A. Risk Factors for additional information regarding risks that may impact our business, financial condition and results of operations.


46


FIRSTENERGY CORP.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
Earnings available to FirstEnergy Corp. in 2011 were $885 million, or $2.22 per basic share of common stock ($2.21 diluted), compared with $742 million, or $2.44 per basic share of common stock ($2.42 diluted), in 2010 and $872 million, or $2.87 per basic share ($2.85 diluted), in 2009.
Change in Earnings Per Basic Share From Prior Year 2011 2010
     
Earnings Per Basic Share — Prior Year $2.44
 $2.87
Segment operating results(1)-
    
Regulated Distribution 0.05
 0.04
Competitive Energy Services (0.15) 0.10
Regulated Independent Transmission (0.06) 0.12
Non-core asset sales/impairments 0.67
 (0.37)
Generating plant impairments 0.08
 (0.78)
Trust securities impairments 0.02
 0.03
Litigation resolution (0.07) 0.01
Regulatory charges 0.03
 0.45
Mark-to-market adjustments-    
Pension and OPEB actuarial assumptions (0.47) 0.30
All other 0.02
 0.35
Organizational restructuring - 2009 —
 0.14
Debt redemption premiums (0.01) 0.32
Merger-related costs (0.29) (0.16)
Merger Accounting - commodity contracts (0.26) —
Net merger accretion(1)(2)(3)
 0.54
 —
Income tax resolution / retiree drug subsidy (0.03) (0.57)
Settlement of uncertain tax positions (0.05) (0.11)
Depreciation (0.09) (0.02)
Interest expense, net of amounts capitalized (0.14) 0.04
Investment income (0.03) (0.19)
Change in effective tax rate 0.04
 (0.17)
Other (0.02) 0.04
Earnings Per Basic Share $2.22
 $2.44
(1)Excludes amounts that are shown separately
(2)Includes dilutive effect of shares issued in connection with the Allegheny merger
(3)Includes 10 months of Allegheny results in 2011

Merger
On February 25, 2011, the merger between FirstEnergy and AE closed. Pursuant to the terms of the Agreement and Plan of Merger between FirstEnergy, Merger Sub and AE, Merger Sub merged with and into AE with AE continuing as the surviving corporation and a wholly owned subsidiary of FirstEnergy. As part of the merger, AE shareholders received 0.667 of a share of FirstEnergy common stock for each AE share outstanding as of the merger completion date and all outstanding AE equity-based employee compensation awards were converted into FirstEnergy equity-based awards on the same basis.
In connection with the merger, FirstEnergy recorded merger transaction costs of approximately $91 million ($73 million net of tax and $65 million ($47 million net of tax) during 2011 and 2010, respectively. These costs are included in “Other operating expenses” in the Consolidated Statements of Income. In addition, during 2011, $93 million of pre-tax merger integration costs and $36 million of pre-tax charges from merger settlements approved by regulatory agencies were recognized. Charges resulting from merger settlements are not expected to be material in future periods.
FirstEnergy exceeded its 2011 merger benefits target. During 2011, FirstEnergy completed savings initiatives that allowed the


47


company to capture pre-tax annualized merger benefits of approximately $267 million compared to the annual target of $210 million.

Operational Matters

PJM RTO Integration

On June 1, 2011, ATSI successfully integrated into PJM. With this transition, all of FirstEnergy's generation, transmission and distribution facilities are now in PJM.

Transmission Expansion

On May 19, 2011, TrAIL's 500-kV transmission line, spanning more than 150 miles from southwestern Pennsylvania through West Virginia to northern Virginia, was completed and energized.

Nuclear Generation

On April 11, 2011, Beaver Valley Power Station Unit 2 returned to service following a March 7, 2011 shutdown for refueling and maintenance. During the outage, 60 of the 157 fuel assemblies were exchanged, safety inspections were conducted, and numerous maintenance and improvement projects were completed that we believe will result in continued safe and reliable operations.

On June 7, 2011, the Perry Nuclear Power Plant returned to service following a scheduled shutdown for refueling and maintenance which began on April 18, 2011. During the outage, 248 of the 748 fuel assemblies were replaced and safety inspections were successfully conducted. Additionally, numerous preventative maintenance activities and improvement projects were completed that we believe will result in continued safe and reliable operations, including replacement of several control rod blades, rewind of the generator, and routine work on more than 150 valves, pumps and motors.

On October 2, 2011, FENOC completed the controlled shutdown of the Perry Plant due to the loss of a startup transformer. Subsequently, a spare replacement transformer from Davis-Besse Nuclear Power Station was transported to the Perry Plant for modification and installation. The new transformer was installed in 2011.

During 2011, FENOC broke ground for new Emergency Operations Facilities at all three of its nuclear sites. Each of the 12,000 square-foot facilities will house activities related to maintaining public health and safety during the unlikely event of an emergency at the plant and allow for improved coordination between the plant, state and local emergency management agencies.

On October 1, 2011, the Davis-Besse Nuclear Power Station began a scheduled outage for replacement of its reactor vessel head and other scheduled maintenance. On October 10, 2011, following opening of the building for installation of the new reactor head, a sub-surface hairline crack was identified in one of the exterior architectural elements on the shield building. These elements serve as architectural features and do not have structural significance. During investigation of the crack at the shield building opening, concrete samples and electronic testing found similar sub-surface hairline cracks in most of the building's architectural elements. FENOC's investigation also identified other indications of cracking. Included among them were sub-surface hairline cracks in the upper portion of the shield building (above 780 feet of elevation) and in the vicinity of the main steam line penetrations. A team of industry-recognized structural concrete experts and Davis-Besse engineers have determined these conditions do not affect the facility's structural integrity or safety. On February 27, 2012, FENOC sent a root cause evaluation report to the NRC. On December 6, 2011, the Davis-Besse Nuclear Power Station returned to service. The new reactor vessel head features control rod nozzles made of an enhanced material and further promotes safe and reliable operation of the plant.

Coal and Gas Fired Generation

On July 28, 2011, FirstEnergy completed the sale of the Fremont Energy Center to American Municipal Power, Inc. for $510 million based on 685 MW of output. The purchase price can be incrementally increased, not to exceed an additional $16 million, to reflect additional transmission export capacity up to 707 MW.

On October 18, 2011, FirstEnergy sold its Richland (432 MW) and Stryker (18 MW) Peaking Facilities for approximately $80 million. The proceeds from the sale of these non-core assets reduced FirstEnergy's net debt position.

On January 26, 2012, FirstEnergy announced that its unregulated generation subsidiaries will retire six older coal-fired plants located in Ohio, Pennsylvania and Maryland. On February 8, 2012, FirstEnergy announced that MP will retire three older coal-fired plants located in West Virginia. All of these generating plants will be closed by September 1, 2012. The decision to close the plants is the result of a comprehensive review of FirstEnergy's coal-fired generating facilities in light of the MATS rules that were recently finalized and other environmental regulations. These closures are subject to review for reliability impacts by PJM. In addition, MP will make a filing with the WVPSC to provide them with information regarding the retirement of its plants. As a result of this decision, impairment charges associated with these assets were recognized by FirstEnergy, aggregating approximately $334 million ($207 million after-tax) in the fourth quarter of 2011, including approximately $243 million ($152 million after-tax) which is applicable to FES. See Note 11, Impairment of Long-lived Assets, for further information on the retirement of these plants.



48


The total capacity of the competitive plants that will be retired is approximately 2,700 MW and the total capacity of the three regulated plants that will be retired is approximately 660 MW. Recently, these plants served mostly as peaking or intermediate facilities, generating, on average, approximately 10 percent of the electricity produced by FirstEnergy's generation subsidiaries over the past three years.

On February 24, 2012, PJM notified FirstEnergy of its preliminary analysis of the reliability impacts that may result from closure of the older competitive coal-fired generating units. PJM's preliminary analysis indicated that there would be significant reliability concerns that will need to be addressed. FirstEnergy intends to continue to actively engage in discussions with PJM regarding this notification, including the possible continued operation of certain plants.

Signal Peak

On October 18, 2011, FirstEnergy announced that Gunvor Group, Ltd. purchased a one-third interest in Global Holding, a joint venture that owns the Signal Peak coal mine in Montana and the related Global Rail coal transportation operations. The sale strengthened FirstEnergy's balance sheet in the following ways:

Proceeds of $257.5 million reduced FirstEnergy's net debt position;
De-consolidation of Signal Peak resulted in the reduction of indebtedness by $360 million and an increase to equity of $50 million on FirstEnergy's Consolidated Balance Sheet; and
The gain on sale and revaluation of FirstEnergy's remaining ownership stake increased equity by an additional $370 million.

Following the sale, FirstEnergy, through its wholly owned subsidiary, FEV, has a one-third interest in Global Holding. FGCO has a long-term coal supply agreement with Signal Peak for up to 10 million tons per year. FGCO has re-evaluated its coal usage under that agreement and has determined to resell its coal purchased from Signal Peak to an affiliate of Global Holding; provided, however, that such affiliate may require FGCO to repurchase up to 2 million tons annually from the existing underground mines, and, if Signal Peak develops surface mines, it could require FGCO to purchase an additional 2 million tons per year. FirstEnergy remains a 100% guarantor on Signal Peak's and Global Rail's $350 million senior secured credit facility. See Guarantees and Other Assurances below.

FirstEnergy Utilities Respond to Unprecedented Storms

In late August 2011, FirstEnergy experienced unprecedented damage in its service territory as a result of Hurricane Irene. Approximately 1.1 million customers were affected by outages in areas served by JCP&L, Met-Ed, Penelec and PE. Approximately 5,000 FirstEnergy employees and 2,800 contractors, including utility line workers from other utilities, assisted with the restoration work. The cost of the storm totaled approximately $89 million, of which $4 million reduced pre-tax income in 2011 and $85 million was capitalized or deferred for future recovery from customers.

On October 29, 2011, FirstEnergy was affected by a snowstorm that paralyzed much of the East Coast, including our eastern service areas. Approximately 820,000 customers of JCP&L, Met-Ed, PE, MP, Penelec and WP were affected by the storm that brought down more than 800 poles and approximately 10,000 spans of wire. More than 9,600 employees, contractors and other utilities' crews helped in the restoration. The pre-tax total cost of the storm was approximately $125 million, of which $6 million reduced pre-tax income in 2011 and $119 million was capitalized or deferred for future recovery from customers.

Financial Matters
During 2011, FirstEnergy redeemed or repurchased approximately $520.4 million principal amount of PCRBs, as summarized in the following table. Approximately $28.5 million of FGCO FMBs and $98.9 million of NGC FMBs associated with the PCRBs were returned for cancellation by the associated LOC providers.
SubsidiariesAmount 
 (In millions) 
AE Supply$53.0
(1) 
FGCO$198.2
(2) 
NGC$213.5
(2) 
MP$70.2
(1) 
(1)
Includes $14.4 million of PCRBs redeemed for which MP and AE Supply are co-obligors.
(2)
Subject to market conditions, these PCRBs are being held for future remarketing.

On May 4, 2011, AE terminated its $250 million credit facility due to other available funding sources following completion of the merger with FirstEnergy.

On June 17, 2011, FirstEnergy and certain of its subsidiaries entered into two 5-year revolving credit facilities with a total borrowing capacity of $4.5 billion. These facilities consist of a $2 billion revolving credit facility for FirstEnergy and its regulated utility subsidiaries


49


and a $2.5 billion revolving credit facility for FES and AE Supply. Prior separate facilities ($2.75 billion at FirstEnergy, $1 billion at AE Supply, $110 million at MP, $150 million at PE and $200 million at WP) were terminated.

During the third quarter of 2011, FirstEnergy received approximately $130 million from assigning a substantially below-market, long-term fossil fuel contract to a third party. As a result, FirstEnergy entered into a new long-term contract with another supplier for replacement fuel based on current market prices. The new contract runs for nine years, which is the remaining term of the assigned contract. The transaction reduced fuel costs during the quarter by approximately $123 million.

TrAIL's primary investment, the Trans-Allegheny Interstate Line (a 500-kV transmission project that extends from Southwestern Pennsylvania through West Virginia to Northern Virginia), was completed in May 2011.

On January 26, 2012, FirstEnergy announced a change to its method for accounting for pensions and OPEB effective in 2011 (see Note 1, Organization, Basis of Presentation and Significant Accounting Policies of the Combined Notes to the Consolidated Financial Statements). We also disclosed that we made a $600 million voluntary contribution to our pension plan earlier that month.

Regulatory Matters

Met-Ed and Penelec Transition to Competitive Markets

The Pennsylvania Companies began the move to competitive markets with the expiration of the rate caps on Met-Ed's and Penelec's retail generation rates on December 31, 2010. Beginning in 2011, Met-Ed and Penelec obtained their power supply from the competitive wholesale market and fully recover their generation costs through retail rates. The Ohio Companies, Penn, WP and JCP&L previously transitioned to competitive generation markets.

Marginal transmission loss recovery

On March 3, 2010, the PPUC issued an order denying Met-Ed and Penelec the ability to recover marginal transmission losses through the transmission service charge riders in their respective tariffs which applies to the periods including June 1, 2008 through December 31, 2010. Subsequently, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania (Commonwealth Court) appealing the PPUC's order. On June 14, 2011, the Commonwealth Court affirmed the PPUC's decision that marginal transmission losses are not recoverable as transmission costs. On July 13, 2011, Met-Ed and Penelec filed a federal complaint with the United States District Court for the Eastern District of Pennsylvania and on the following day, filed a Petition for Allowance of Appeal to the Pennsylvania Supreme Court. Met-Ed and Penelec believe the Commonwealth Court's decision contradicts federal law and is inconsistent with prior PPUC and court decisions and therefore expect to fully recover the related regulatory assets ($189 million for Met-Ed and $65 million for Penelec). In January 2011 and continuing for 29 months, pursuant to a related PPUC order, Met-Ed and Penelec began crediting customers for the amounts at issue pending the outcome of court appeals.

Ohio Energy Efficiency and Peak Demand Reduction Portfolio Plan

On March 23, 2011, the PUCO approved the three-year Energy Efficiency and Demand Reduction portfolio plan for the Ohio Companies. The Ohio Companies' plan was developed to comply with the Energy Efficiency mandate in Ohio's SB 221, passed in 2008. This law requires that utilities in Ohio reduce energy usage by 22.2 percent by 2025 and peak demand by 7.75 percent by 2018, develop a portfolio plan, and meet annual benchmarks to measure progress.

NYSEG Ruling

On July 11, 2011, FirstEnergy was found to be a potentially responsible party under CERCLA indirectly liable for a portion of past and future clean-up costs at certain legacy MGP sites in New York. As a result, FirstEnergy recognized additional expense of $29 million during the second quarter of 2011.

West Virginia Fuel, Purchased Power Cost Decision

On December 30, 2011, MP and PE announced that the WVPSC issued an order regarding the companies' adjustment of fuel and purchased power costs. The WVPSC's order approved a settlement agreement between the companies, the Consumer Advocate Division, the Staff of the WVPSC and the West Virginia Energy Users Group. In the approved settlement, parties have agreed that the companies will recover an additional $19.6 million in 2012, an approximate 1.7 percent increase, primarily reflecting rising coal prices over the past two years, with certain additional amounts to be recovered over time with a carrying charge.
FIRSTENERGY’S BUSINESS
With the completion of the AE merger in the first quarter of 2011, FirstEnergy reorganized its management structure, which resulted in changes to its operating segments to be consistent with the manner in which management views the business. The new structure supports the combined company's primary operations - distribution, transmission, generation and the marketing and sale of its products. The external segment reporting is consistent with the internal financial reporting used by FirstEnergy's chief executive


50


officer (its chief operating decision maker) to regularly assess the performance of the business and allocate resources. FirstEnergy now has three reportable operating segments - Regulated Distribution, Regulated Independent Transmission and Competitive Energy Services.
Prior to the change in composition of business segments, FirstEnergy's business was comprised of two reportable operating segments. The Energy Delivery Services segment was comprised of FirstEnergy's then eight existing utility operating companies that transmit and distribute electricity to customers and purchase power to serve their POLR and default service requirements. The Competitive Energy Services segment was comprised of FES, which supplies electric power to end-use customers through retail and wholesale arrangements. The “Other/Corporate” amounts consisted of corporate items and other businesses that were below the quantifiable threshold for separate disclosure. Disclosures for FirstEnergy's operating segments for 2010 have been reclassified to conform to the revised presentation.
The changes in FirstEnergy's reportable segments during 2011 consisted primarily of the following:
Energy Delivery Services was renamed Regulated Distribution and the operations of MP, PE and WP, which were acquired as part of the merger with AE, and certain regulatory asset recovery mechanisms formerly included in the “Other/Corporate” segment, were placed into this segment.
A new Regulated Independent Transmission segment was created consisting of ATSI, and the operations of TrAIL and FirstEnergy's interest in PATH; TrAIL and PATH were acquired as part of the merger with AE. The transmission assets and operations of JCP&L, Met-Ed, Penelec, MP, PE and WP remained within the Regulated Distribution segment.
AE Supply, an operator of generation facilities that was acquired as part of the merger with AE, was placed into the Competitive Energy Services segment with FES.

Regulated Distribution distributes electricity through our ten utility distribution companies, serving approximately 6 million customers within 67,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also includes the transmission operations of JCP&L, Met-Ed, Penelec, WP, MP and PE and the regulated electric generation facilities in West Virginia and New Jersey which MP and JCP&L, respectively, own or contractually control. Its results reflect the commodity costs of securing electric generation and the deferral and amortization of certain fuel costs.
The service areas of our regulated distribution utilities are summarized below:
CompanyArea ServedCustomers Served
OECentral and Northeastern Ohio1,032,000
PennWestern Pennsylvania161,000
CEINortheastern Ohio747,000
TENorthwestern Ohio309,000
JCP&LNorthern, Western and East Central New Jersey1,099,000
Met-EdEastern Pennsylvania553,000
PenelecWestern Pennsylvania590,000
WPSouthwest, South Central and Northern Pennsylvania718,000
MPNorthern, Central and Southeastern West Virginia387,000
PEWestern Maryland and Eastern West Virginia390,000
5,986,000

Regulated Independent Transmission transmits electricity through transmission lines and its revenues are primarily derived from a formulaic rate that recovers costs and a return on investment for capital expenditures in connection with TrAIL, PATH and other projects, revenues from providing transmission services to electric energy providers and power marketers, and revenues from operating a portion of the FirstEnergy transmission system. Its results reflect the net transmission expenses related to the delivery of the respective generation loads.

Competitive Energy Services supplies, through FES and AE Supply, electric power to end-use customers through retail and wholesale arrangements, including competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland and the provision of partial POLR and default service for some utilities in Ohio, Pennsylvania and Maryland, including but not limited to the Utilities. This segment controls approximately 17,000 MWs of capacity (excluding approximately 2,700 MWs from unregulated plants expected to be closed by September 1, 2012) (see Note 11, Impairment of Long-Lived Assets of the Combined Notes to the Consolidated Financial Statements) and also purchases electricity to meet sales obligations. The segment's net income is primarily derived from electric generation sales less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO (prior to June 1, 2011)


51


to deliver energy to the segment's customers.
Other/Corporate contains corporate items and other businesses that are below the quantifiable threshold for separate disclosure as a reportable segment. (See Note 19, Segment Information of the Combined Notes to the Consolidated Financial Statements for further information on FirstEnergy's reportable operating segments.)
STRATEGY AND OUTLOOK

FirstEnergy's vision is to be a leading regional energy provider, recognized for operational excellence, outstanding customer service and our commitment to safety; the choice for long-term growth, investment value and financial strength; and a company driven by the leadership, skills, diversity and character of our employees.

FirstEnergy has grown over the last 15 years through several strategic mergers and asset transactions. Our most recent merger with Allegheny was completed in February 2011, significantly increasing our customer base and generating capacity and accelerating our movement further into eastern competitive markets. Also during 2011, we completed the transition to competitive markets in Pennsylvania and moved our ATSI assets into PJM, so that we now operate within a single regional transmission system.

FirstEnergy is uniquely positioned as the nation's largest contiguous electric system, with complementary assets across our generation, transmission and distribution delivery operations. These assets are in a prime location of PJM's competitive markets.

Our substantial regulated operations include 10 distribution utilities serving a balanced base of nearly 6 million customers across 5 states. We are also one of the largest owners of transmission assets in PJM with nearly 20,000 miles of high-voltage lines, including two independent transmission companies with significant assets. Combined, our utilities and transmission operations provide financial stability with strong cash flow and dividend support to FirstEnergy.

Our market-focused business model integrates more than 17,000 MWs of competitive generation, excluding approximately 2,700 MWs from unregulated plants expected to be closed by September 1, 2012, and are subject to review by PJM for reliability impacts(see Note 16, Commitment, Guarantees and Contingencies, regarding PJM's review of the our plans), with a multi-channel retail sales platform, providing a higher value for every MWH we generate. We primarily target customers in competitive markets close to our generation assets.

We believe we are well-positioned for upcoming environmental changes due to the considerable investments we have made in recent years to diversify our generation fleet and improve its environmental performance. As a result of the MATS rules recently finalized by the EPA, and other previously announced environmental regulations, FirstEnergy announced in early 2012 its intent to retire nine older coal-fired power plants, totaling 3,349 MW, located in Ohio, Pennsylvania, Maryland and West Virginia by September 1, 2012. When the retired fossil plants are removed from our fleet, nearly 100% percent of our generation output will be from either low or non-emitting facilities, including nuclear, hydro, natural gas and scrubbed coal units. This further positions our fleet to deliver superior value in the future.

We continue to face challenges related to macro-economic factors. These include slow economic recovery across portions of our service territory, which affect our distribution deliveries volumes to residential, commercial and industrial customers, and depressed natural gas and wholesale electricity prices, which affect revenues from our competitive retail business and generation fleet. However, we believe we are one of the better positioned companies in our industry to benefit from eventual increases in energy and capacity prices as economic conditions improve.

Financial Outlook

We intend to manage our operating and capital costs in order to achieve our financial goals and commitment to shareholders.

Our liquidity position remains strong, with approximately $49 million of short-term cash investments and over $4.3 billion of available liquidity as of January 31, 2012.

Positive earnings drivers for 2012 are expected to include:

▪A full year contribution from the Allegheny merger;

▪Higher competitive retail revenues as a result of continued growth in the business;

▪Lower fuel and operation and maintenance expenses due to the retirement of certain coal-fired plants in 2012 and from a continued focus on controlling our costs; and

▪Reduced interest expense as a result of debt redemptions during 2011.

Negative earnings drivers for 2012 are expected to include:

▪Lower margins for our competitive energy service business from depressed market prices of power and lower capacity


52


prices resulting from the PJM RPM auction beginning June 1, 2012;

▪Higher gross receipts taxes associated with increased competitive retail sales in Pennsylvania; and

▪Increased depreciation expenses from capital projects that were placed in service during 2011.

On January 5, 2012, we made a $600 million voluntary contribution to our pension plan bringing its funding level to 90% on an accumulated benefit obligation basis.

Capital Expenditures Outlook

Our capital expenditures in 2012 are estimated to be $2.1 billion (excluding nuclear fuel), a decrease of approximately $393 million from 2011. In addition to internal sources to fund capital requirements for 2012 and beyond, FirstEnergy expects to rely on external sources of funds.

Capital expenditures for our Regulated Distribution segment are forecast to decrease by $63 million in 2012 from $1.1 billion in 2011. The expected decrease primarily reflects the absence of storm restoration costs related to Hurricane Irene and the October 2011 snowstorm. For our Regulated Independent Transmission segment, capital expenditures are expected to decrease to $105 million in 2012 from $190 million in 2011. The decrease reflects the completion of TrAIL's 500-kV transmission line in 2011.

Expenditures for Ohio and Pennsylvania energy efficiency and advanced metering initiatives are expected to be primarily recovered from distribution customers and federal stimulus funding. Other capital investments in our transmission and distribution infrastructure are planned to satisfy transmission capacity and reliability requirements, connect new load delivery and wholesale generation points, and achieve cost-effective improvements in the reliability of our service.

For our Competitive Energy Services segment, capital expenditures are expected to increase by $32 million to $803 million in 2012. The main drivers of the increase include steam generator replacement projects at Davis-Besse and Beaver Valley Unit 2 and turbine rotor replacement projects at Perry and Beaver Valley Unit 2. Other planned generation investments provide for maintenance of critical generation assets, delivering operational improvements to enhance reliability, supporting environmental compliance, and advancing our generation to market strategy.

For 2013, we anticipate baseline capital expenditures of approximately $2.0 billion, which exclude any potential additional strategic opportunities, future mandated spending, energy efficiency or environmental spending relating to MATS. Planned capital initiatives are intended to promote reliability, improve operations, and support current environmental and energy efficiency directives.

Environmental Outlook

We continually strive to enhance environmental protection and remain good stewards of our natural resources. We devote significant resources to environmental compliance efforts, and our employees share a commitment to, and accountability for, environmental performance. Our corporate focus on continuous improvement is integral to our environmental programs.

We have spent more than $10 billion on environmental protection efforts since the initial passage of the Clean Air and Water Acts in the 1970s, and these investments demonstrate our continuing commitment to the environment. Recent investments of $3.0 billion at our Hatfield, Fort Martin and Sammis Plants, further reduced emissions of SO2 by over 95%, and NOx by at least 64% at these facilities. Since 1990, we have reduced emissions of NOx by more than 76%, SO2 by more than 86%, and mercury by approximately 56%.

We have taken aggressive steps over the past two decades that have increased our generating capacity without adding to overall CO2 emissions. For example, since 1990, we have reconfigured our fleet by retiring 1,312 MWs and committing to retire in the near future 3,349 MWs of older, coal-based generation and adding more than 1,800 MWs of non-emitting capacity. Through these and other actions, we have increased our generating capacity by nearly 15% over the same period while avoiding over 370 million metric tons of CO2 emissions.

We have taken a leadership role in pursuing new ventures to test and develop new technologies that may achieve additional reductions in CO2 emissions. These include:

Sales of over 1 million MWH per year of wind generation.

CO2 sequestration testing to gain a better understanding of the potential for geological storage of CO2.

Supporting afforestation - growing forests on non-forested land - and other efforts designed to remove CO2 from the environment.

Reducing emissions of SF6 (sulfur hexafluoride) by nearly 15 metric tons, resulting in an equivalent reduction of nearly 315,000 metric tons of CO2, through the EPA's SF6 Emissions Reduction Partnership for Electric Power Systems.



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Supporting research to develop and evaluate cost effective sorbent materials for CO2 capture including work by EPRI and The University of Akron.

We remain actively engaged in the federal and state debate over future environmental requirements and legislation. We actively work with policy makers and regulators to develop fair and reasonable requirements, with the goal of reducing emissions while minimizing the economic impact on our customers. Due to the significant uncertainty as to the final form or timing of a significant number of regulations and legislation at both the federal and state levels, we are unable to determine the potential impact and risks associated with all future environmental requirements. The CSAPR was stayed at the end of 2011 and the federal appeals court reviewing CSAPR has scheduled an April 13, 2012 hearing. The new MATS were finalized at the end of 2011, which resulted in our decision to retire nine older coal-fired generation plants by September 1, 2012. Our current estimate is that it may cost approximately $1.3 - $1.7 billion to bring our remaining units into compliance.

We also have a long history of supporting research in distributed energy resources. Distributed energy resources include fuel cells, solar and wind systems or energy storage technologies located close to the customer or direct control of customer loads to provide alternatives or enhancements to the traditional electric power system. We are testing the world's largest utility-scale fuel cell system to determine its feasibility for augmenting generating capacity during summer peak-use periods. Through a partnership with EPRI, the Cuyahoga Valley National Park, the Department of Defense and Case Western Reserve University, two solid-oxide fuel cells were installed as part of a test program to explore the technology and the environmental benefits of distributed generation.

We are also evaluating the impact of distributed energy storage on the distribution system through analysis and field demonstrations of advanced battery technologies. FirstEnergy's EasyGreen® load-management program utilizes two-way communication capability with customers' non-critical equipment, such as air conditioners in New Jersey and Pennsylvania, to help manage peak loading on the electric distribution system. We have also made an online interactive energy efficiency tool, Home Energy Analyzer, available to our customers to help achieve electricity use reduction goals.
RISKS AND CHALLENGES
In executing our strategy, we face a number of industry and enterprise risks and challenges. See ITEM 1A. RISK FACTORS for a discussion of the risks and challenges faced by FirstEnergy and the Registrants.
RESULTS OF OPERATIONS
The financial results discussed below include revenues and expenses from transactions among FirstEnergy’s business segments. A reconciliation of segment financial results is provided in Note 19, Segment Information of the Combined Notes to the Consolidated Financial Statements. As described in Note 1, Organization, Basis of Presentation and Significant Accounting Policies, FirstEnergy elected to change its method of recognizing actuarial gains and losses for its defined benefit pension and OPEB plans and applied this change retrospectively to all periods presented. Earnings available to FirstEnergy by major business segment were as follows:
       Increase (Decrease)
 2011 2010 2009 2011 vs 2010 2010 vs 2009
 (In millions, except per share data)
Earnings By Business Segment:         
Regulated Distribution$570
 $553
 $335
 $17
 $218
Competitive Energy Services377
 210
 446
 167
 (236)
Regulated Independent Transmission112
 54
 39
 58
 15
Other and reconciling adjustments(1)
(174) (75) 52
 (99) (127)
Earnings available to FirstEnergy Corp.$885
 $742
 $872
 $143
 $(130)
          
Earnings Per Basic Share$2.22
 $2.44
 $2.87
 $(0.22) $(0.43)
          
Earnings Per Diluted Share$2.21
 $2.42
 $2.85
 $(0.21) $(0.43)
(1)
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 — 2011 Compared with 2010
Financial results for FirstEnergy’s major business segments in 2011 and 2010 were as follows:


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2011 Financial Results Regulated Distribution Competitive Energy Services Regulated Independent Transmission Other and Reconciling Adjustments FirstEnergy Consolidated
  (In millions)
Revenues:          
External          
Electric $9,544
 $5,573
 $—
 $—
 $15,117
Other 460
 363
 391
 (140) 1,074
Internal —
 1,237
 —
 (1,170) 67
Total Revenues 10,004
 7,173
 391
 (1,310) 16,258
           
Operating Expenses:          
Fuel 268
 2,049
 —
 —
 2,317
Purchased power 4,672
 1,491
 —
 (1,177) 4,986
Other operating expenses 1,662
 2,256
 68
 (77) 3,909
Pensions and OPEB mark-to-market adjustment 290
 215
 2
 —
 507
Provision for depreciation 620
 415
 60
 26
 1,121
Amortization of regulatory assets, net 323
 —
 6
 —
 329
General taxes 724
 200
 33
 21
 978
Impairment of long-lived assets 87
 315
 —
 11
 413
Total Operating Expenses 8,646
 6,941
 169
 (1,196) 14,560
           
Operating Income 1,358
 232
 222
 (114) 1,698
           
Other Income (Expense):          
Gain on partial sale of Signal Peak —
 569
 —
 —
 569
Investment income 110
 56
 —
 (52) 114
Interest expense (573) (298) (46) (91) (1,008)
Capitalized interest 10
 40
 2
 18
 70
Total Other Income (Expense) (453) 367
 (44) (125) (255)
           
Income Before Income Taxes 905
 599
 178
 (239) 1,443
Income taxes 335
 222
 66
 (49) 574
Net Income 570
 377
 112
 (190) 869
Loss attributable to noncontrolling interest —
 —
 —
 (16) (16)
Earnings available to FirstEnergy Corp. $570
 $377
 $112
 $(174) $885


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2010 Financial Results Regulated Distribution Competitive Energy Services Regulated Independent Transmission Other and Reconciling Adjustments FirstEnergy Consolidated
  (In millions)
Revenues:          
External          
Electric $9,271
 $3,252
 $—
 $—
 $12,523
Other 300
 323
 242
 (123) 742
Internal 139
 2,301
 —
 (2,366) 74
Total Revenues 9,710
 5,876
 242
 (2,489) 13,339
           
Operating Expenses:          
Fuel —
 1,432
 —
 —
 1,432
Purchased power 5,273
 1,724
 —
 (2,373) 4,624
Other operating expenses 1,320
 1,393
 61
 (78) 2,696
Pensions and OPEB mark-to-market adjustment 82
 107
 (2) 3
 190
Provision for depreciation 433
 284
 37
 14
 768
Amortization of regulatory assets, net 712
 —
 10
 —
 722
General taxes 605
 124
 30
 17
 776
Impairment of long-lived assets —
 388
 —
 —
 388
Total Operating Expenses 8,425
 5,452
 136
 (2,417) 11,596
           
Operating Income 1,285
 424
 106
 (72) 1,743
           
Other Income (Expense):          
Investment income 102
 51
 —
 (36) 117
Interest expense (500) (232) (22) (91) (845)
Capitalized interest 4
 95
 2
 64
 165
Total Other Expense (394) (86) (20) (63) (563)
           
Income Before Income Taxes 891
 338
 86
 (135) 1,180
Income taxes 338
 128
 32
 (36) 462
Net Income 553
 210
 54
 (99) 718
Loss attributable to noncontrolling interest —
 —
 —
 (24) (24)
Earnings available to FirstEnergy Corp. $553
 $210
 $54
 $(75) $742



56


Changes Between 2011 and 2010 Financial Results
Increase (Decrease)
 Regulated Distribution Competitive Energy Services Regulated Independent Transmission Other and Reconciling Adjustments FirstEnergy Consolidated
  (In millions)
Revenues:          
External          
Electric $273
 $2,321
 $—
 $—
 $2,594
Other 160
 40
 149
 (17) 332
Internal (139) (1,064) —
 1,196
 (7)
Total Revenues 294
 1,297
 149
 1,179
 2,919
           
Operating Expenses:          
Fuel 268
 617
 —
 —
 885
Purchased power (601) (233) —
 1,196
 362
Other operating expenses 342
 863
 7
 1
 1,213
Pensions and OPEB mark-to-market adjustment 208
 108
 4
 (3) 317
Provision for depreciation 187
 131
 23
 12
 353
Amortization of regulatory assets, net (389) —
 (4) —
 (393)
General taxes 119
 76
 3
 4
 202
Impairment of long-lived assets 87
 (73) —
 11
 25
Total Operating Expenses 221
 1,489
 33
 1,221
 2,964
           
Operating Income 73
 (192) 116
 (42) (45)
           
Other Income (Expense):          
Gain on partial sale of Signal Peak —
 569
 —
 —
 569
Investment income 8
 5
 —
 (16) (3)
Interest expense (73) (66) (24) —
 (163)
Capitalized interest 6
 (55) —
 (46) (95)
Total Other Income (Expense) (59) 453
 (24) (62) 308
           
Income Before Income Taxes 14
 261
 92
 (104) 263
Income taxes (3) 94
 34
 (13) 112
Net Income 17
 167
 58
 (91) 151
Loss attributable to noncontrolling interest —
 —
 —
 8
 8
Earnings available to FirstEnergy Corp. $17
 $167
 $58
 $(99) $143
Regulated Distribution — 2011 Compared with 2010
Net income increased by $17 million in 2011 compared to 2010, primarily due to earnings from the Allegheny companies and the absence of a 2010 regulatory asset impairment associated with the Ohio companies' ESP, partially offset by higher pensions and OPEB mark-to-market adjustment charges and merger-related costs. Lower generation revenues were offset with lower purchased power expenses.


57


Revenues —
The increase in total revenues resulted from the following sources:
  For the year ended December 31  
Revenues by Type of Service 2011 2010 
Increase
(Decrease)
  (In millions)
Pre-merger companies:      
Distribution services $3,426
 $3,629
 $(203)
Generation:      
Retail 3,266
 4,457
 (1,191)
Wholesale 377
 702
 (325)
Total generation sales 3,643

5,159
 (1,516)
Transmission 262
 596
 (334)
Other 187
 326
 (139)
Total pre-merger companies 7,518
 9,710
 (2,192)
Allegheny companies 2,486
 —
 2,486
Total Revenues $10,004
 $9,710
 $294

The decrease in distribution service revenues for the pre-merger companies (FirstEnergy as it was organized prior to the February 2011 merger with Allegheny) primarily reflects lower transition revenues due to the completion of transition cost recovery by CEI in December 2010, an NJBPU-approved rate adjustment that became effective March 1, 2011, for all JCP&L customer classes, and the mid-year suspension of the Ohio Companies' recovery of deferred distribution costs. Partially offsetting the decreased distribution service revenues were increased rates in Met-Ed's and Penelec's transition riders and energy efficiency riders for the Pennsylvania and Ohio Companies. Distribution deliveries (excluding the Allegheny companies) increased by 0.1% in 2011 from 2010.The change in distribution deliveries by customer class is summarized in the following table:
  For the year ended December 31  
Electric Distribution MWH Deliveries 2011 2010 
Increase
(Decrease)
     
Pre-merger companies:      
Residential 39,369
 39,820
 (1.1)%
Commercial 32,610
 33,096
 (1.5)%
Industrial 35,637
 34,613
 3.0 %
Other 513
 522
 (1.7)%
Total pre-merger companies 108,129
 108,051
 0.1 %
Allegheny companies 33,449
    
Total Electric Distribution MWH Deliveries 141,578
 108,051
 31.0 %

Lower deliveries to residential and commercial customers primarily reflected decreased weather-related usage resulting from lower heating degree days (4%) and cooling degree days (7%) in 2011 compared to 2010. In the industrial sector, MWH deliveries increased to steel and electrical equipment customers by 10% and 12%, respectively, partially offset by decreased deliveries to automotive customers of 2% in 2011 compared to 2010.


58


The following table summarizes the price and volume factors contributing to the $1,516 million decrease in generation revenues for the pre-merger companies in 2011 compared to 2010:
Source of Change in Generation Revenues 
Increase
(Decrease)
  (In millions)
Retail:  
Effect of decrease in sales volumes $(1,638)
Change in prices 447
  (1,191)
Wholesale:  
Effect of decrease in sales volumes (104)
Change in prices (221)
  (325)
Net Decrease in Generation Revenues $(1,516)

The decrease in retail generation sales volume was primarily due to increased customer shopping in the service territories of the pre-merger companies in 2011 compared to 2010. Total generation provided by alternative suppliers as a percentage of total MWH deliveries increased to 76% from 62% for the Ohio Companies, and to 52% from 10% in Met-Ed’s, Penelec’s and Penn's service territories. The increase in retail prices is the result of higher generation charges in Pennsylvania due to the removal of generation rate caps for Met-Ed and Penelec beginning on January 1, 2011, and the inclusion of transmission as part of the price of generation. Those impacts were partially offset by a decrease in the Ohio Companies' generation rates beginning in June 2011 with the removal of certain transmission charges in connection with the integration into PJM.
The decrease in wholesale generation revenues reflected lower RPM revenues for Met-Ed and Penelec in the PJM market.
Transmission revenues decreased $334million primarily due to the termination of Met-Ed’s and Penelec’s TSC rates effective January 1, 2011. This is partially offset by a new rider that became effective for the Ohio Companies in June 2011 that recovers network integration transmission service charges.
Other revenues decreased by $139 million primarily due to the termination of Met-Ed's and Penelec's PSA with FES as of December 31, 2010, resulting in decreased capacity revenues.
The Allegheny companies added $2,486 million to revenues in 2011, including $571 million for distribution services, $1,661million from generation sales, $212 million of transmission revenues and $42 million of other revenues.
Operating Expenses —
Total operating expenses increased by $221 million in 2011. Excluding the Allegheny companies, total operating expenses decreased $1.9 billion due to the following:

Purchased power costs were $1.7 billion lower in 2011 due primarily to a decrease in volumes required. Decreased power purchased from FES primarily reflected the increase in customer shopping described above, the termination of Met-Ed’s and Penelec’s PSA with FES at the end of 2010, and less Ohio POLR load served by FES beginning in June 2011. The increase in volumes purchased from non-affiliates in 2011 is primarily due to Met-Ed’s and Penelec’s generation procurement plan effective January 1, 2011 and more Ohio POLR load served by non-affiliates, partially offset by a decrease in RPM expenses in the PJM market.


59


Source of Change in Purchased Power 
Increase
(Decrease)
  (In millions)
Pre-merger companies:  
Purchases from non-affiliates:  
Change due to decreased unit costs $(826)
Change due to increased volumes 515
  (311)
Purchases from FES:  
Change due to increased unit costs 165
Change due to decreased volumes (1,601)
  (1,436)
   
Total pre-merger companies (1,747)
Purchases by Allegheny companies 1,146
Net Decrease in Purchased Power Costs $(601)
Other operating expenses decreased $37 million, primarily due to the following:
◦Storm restoration maintenance and removal expenses increased $126 million primarily related to restoration associated with Hurricane Irene and an October 2011 East Coast snowstorm, primarily impacting the JCP&L and Met-Ed service territories. Approximately $120 million of the total costs were deferred for future recovery from customers.
◦Energy efficiency program costs, which are also recovered through rates, increased by $92 million.
◦
A provision for excess and obsolete material of $13 million was recognized in 2011 due to revised inventory practices adopted in conjunction with the Allegheny merger.
◦The absence of a $7 million favorable JCP&L labor settlement that occurred in 2010.
◦Transmission expenses decreased $285 million primarily due to reduced congestion costs for Met-Ed and Penelec in 2011.
Pensions and OPEB mark-to-market adjustment charges increased $132 million as a result of higher net actuarial losses.
Depreciation expense increased $24 million primarily due to property additions since 2010.
Net amortization of regulatory assets decreased $368 million primarily due to reduced net PJM transmission and transition cost recovery, the absence of a $35 million regulatory asset impairment recognized in 2010 associated with the filing of the Ohio Companies' ESP on March 23, 2010, and the deferral of recoverable costs from Hurricane Irene and the 2011 East Coast snowstorm, partially offset by increased energy efficiency cost recovery.
General Taxes increased $10 million due to the absence of a favorable property tax settlement recognized in 2010.
Impairments of long-lived assets totaling $87 million in 2011 resulted from the pending shutdown of three coal-fired plants in West Virginia.


60


The acquisition of the Allegheny companies resulted in the inclusion of the following operating expenses in 2011:
Operating Expenses - Allegheny In Millions
   
Purchased power $1,146
Fuel 268
Transmission 120
Amortization of regulatory assets, net (21)
Pensions and OPEB mark-to-market adjustment 76
Other operating expenses 259
General taxes 109
Depreciation expense 163
Total Operating Expenses $2,120
Other Expense —
Other expense increased $59 million in 2011 due to interest expense on debt of the Allegheny companies partially offset by higher investment income on OE's and TE's nuclear decommissioning trusts and increased capitalized interest.
Regulated Independent Transmission — 2011 Compared with 2010
Net income increased by $58 million in 2011 compared to 2010 due to earnings associated with TrAIL and PATH of $79 million, partially offset by decreased earnings for ATSI of $20 million.
Revenues —
Total revenues increased by $149 million principally due to revenues from TrAIL and PATH, which were acquired as part of the merger with Allegheny, partially offset by a decrease in ATSI revenues due to the transition from MISO to PJM and the completion of vegetation management cost recovery in May 2011.
Revenues by transmission asset owner are shown in the following table:
Revenues by Transmission Asset Owner 2011 2010 
Increase
(Decrease)
  (In millions)
ATSI $207
 $242
 $(35)
TrAIL 170
 —
 170
PATH 14
 —
 14
Total Revenues $391
 $242
 $149
Operating Expenses —
Total operating expenses increased by $33 million principally due to the addition of TrAIL and PATH in 2011.
Other Expense —
Other expense increased $24 million in 2011 due to additional interest expense associated with TrAIL.
Competitive Energy Services — 2011 Compared to 2010
Net income increased by $166 million in 2011 compared to 2010. The increase in net income was primarily due to a $569 million gain ($358 million net of tax) on the partial sale of FEV's interest in Signal Peak in 2011 and decreased impairments of long-lived assets. Partially offsetting this was a decrease in sales margins of $193 million, a $66 million increase in interest expense and a $55 million decrease in capitalized interest compared to 2010.
Revenues —
Total revenues increased $1.3 billion in 2011 compared to 2010, primarily due to an increase in direct and governmental aggregation sales and the inclusion of the Allegheny companies, partially offset by a decline in POLR and structured sales.


61


The increase in reported segment revenues resulted from the following sources:
Revenues by Type of Service 2011 2010 Increase (Decrease)
  (In millions)
Direct and Governmental Aggregation $3,785
 $2,493
 $1,292
POLR and Structured Sales 944
 2,589
 (1,645)
Wholesale 457
 397
 60
Transmission 108
 77
 31
RECs 67
 74
 (7)
Sale of OVEC participation interest —
 85
 (85)
Other 173
 161
 12
Allegheny Companies 1,639
 —
 1,639
Total Revenues $7,173
 $5,876
 $1,297
       
Allegheny Companies      
Direct and Government Aggregation $84
   

POLR and Structured Sales 561
   

Wholesale 912
   

Transmission 88
   

Other (6)   

Total Revenues $1,639
 

 

MWH Sales by Type of Service 2011 2010 Increase (Decrease)
  (In thousands)
Direct 46,187
 28,499
 17,688
Government Aggregation 17,722
 12,796
 4,926
POLR and Structured Sales 15,340
 50,358
 (35,018)
Wholesale 2,916
 5,391
 (2,475)
Allegheny Companies 26,609
 —
 26,609
Total Sales 108,774
 97,044
 11,730
       
Allegheny Companies      
Direct 1,390
   

POLR 7,974
   

Structured Sales 1,492
   

Wholesale 15,753
   

Total Sales 26,609
 




The increase in direct and governmental aggregation revenues of $1.3 billion resulted from the acquisition of new residential, commercial and industrial customers, as well as new governmental aggregation contracts with communities in Ohio and Illinois that provide generation to approximately 1.8 million residential and small commercial customers at the end of 2011 compared to approximately 1.5 million customers at the end of 2010. Increases in direct sales volume were partially offset by lower unit prices.
The decrease in POLR and structured sales revenues of $1.6 billion was due to lower sales volumes to Met-Ed, Penelec and the Ohio Companies, partially offset by increased sales to non-affiliates and higher unit prices to the Pennsylvania Companies. The decline in POLR sales reflects our focus on more profitable sales channels.
Wholesale revenues increased $60 million due to higher wholesale prices partially offset by decreased volumes. The lower sales volumes were the result of decreased short-term (net hourly positions) transactions in MISO, partially offset by increased short-term transactions in PJM. In addition, capacity revenues earned by units that moved to PJM from MISO were partially offset by losses on financially settled sales contracts.



62


The following tables summarize the price and volume factors contributing to changes in revenues from generation sales:
Source of Change in Direct and Governmental Aggregation Increase(Decrease)
  (In millions)
Direct Sales:  
Effect of increase in sales volumes $1,034
Change in prices (75)
  959
Governmental Aggregation:  
Effect of increase in sales volumes 319
Change in prices 14
  333
Net Increase in Direct and Government Aggregation Revenues $1,292
Source of Change in POLR and Structured Revenues 
Increase
(Decrease)
  (In millions)
Effect of decrease in sales volumes $(1,800)
Change in prices 155
  $(1,645)
   
Source of Change in Wholesale Revenues Increase(Decrease)
  (In millions)
Effect of decrease in sales volumes $(182)
Change in prices 242
  $60
Operating Expenses —
Total operating expenses increased $1.5 billion in 2011. Excluding the Allegheny companies, total operating expenses decreased $98 million compared to 2010, due to the following factors:
Fuel costs decreased $177 million in 2011 compared to 2010 primarily due to cash received from assigning a substantially below-market, long-term fossil contract to a third party. In connection with its merger integration initiatives and risk management strategy, FirstEnergy continues to evaluate opportunities with respect to its commodity contracts. As a result of the assignment, FirstEnergy entered into a new long-term contract with another supplier for replacement fuel based on current market prices. Excluding the assignment, fuel costs decreased $54 million in 2011 compared to 2010 due to decreased volumes consumed ($115 million), partially offset by higher unit prices ($61 million). The decrease in fossil fuel expense reflects lower generation needed to satisfy sales requirements. Lower fossil fuel expenses were partially offset by a $22 million increase in nuclear fuel costs, which rose principally due to higher nuclear fuel unit prices following the refueling outages that occurred in 2010 and 2011.
Purchased power costs decreased $382 million as lower volumes ($649 million) were partially offset by higher unit prices ($267 million). The decrease in volume primarily relates to the expiration at the end of 2010 of a 1,300 MW third party contract associated with serving Met-Ed and Penelec.
Fossil operating costs increased $36 million due primarily to higher labor, contractor and material costs resulting from an increase in planned and unplanned outages, which were partially offset by reduced losses from the sale of excess coal.
Nuclear operating costs increased $53 million primarily due to Perry and Beaver Valley Unit 2 refueling outages in 2011. While Davis-Besse had a refueling outage in 2010 and an outage in 2011 to replace the reactor vessel head, the work performed on both outages was largely capital-related.
Transmission expenses increased $249 million due primarily to higher congestion, network and line loss expenses.
Depreciation expense increased $20 million principally due to the completion of the Sammis projects at the end of 2010.
General taxes increased $36 million due to an increase in revenue-related taxes.


63


Impairments of long-lived assets decreased $85 million compared to last year. The 2011 charges are due to the pending shutdown of six unregulated, coal-fired generating units; charges in 2010 related to operational changes at certain smaller coal-fired units.
Other operating expenses increased $152 million primarily due to a $54 million provision for excess and obsolete material relating to revised inventory practices adopted in connection with the Allegheny merger; a $64 million increase in pensions and OPEB mark-to-market adjustment charges from higher net actuarial losses; a $10 million increase in other mark-to-market adjustments; an $18 million increase in agent fees due to rapid growth in FES' retail business; and a $17 million increase in intercompany billings. The intercompany billings increased due to higher merger-related costs, partially offset by lower leasehold costs from the Ohio Companies.
The inclusion of the Allegheny companies' operations added $1.6 billion to operating expenses as shown in the following table:
Source of Operating Expense Changes Increase (Decrease)
  (In millions)
Allegheny Companies  
Fuel $794
Purchased power 149
Fossil operation and maintenance 152
Transmission 198
Pensions and OPEB mark-to-market adjustment 44
Other mark-to-market 4
Depreciation 111
General taxes 40
Other 96
Total operating expenses $1,588
Other Expense —
Total other expense in 2011 was $453 million lower than 2010, primarily due to a $569 million gain on the partial sale of FEV's interest in Signal Peak and an increase in nuclear decommissioning trust investment income of $5 million, partially offset by a $121 million increase in net interest expense. The net interest expense increase in 2011 from 2010 resulted from lower capitalized interest due to the completion of major environmental projects in 2010.
Other — 2011 Compared to 2010
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 an $99 million decrease in earnings available to FirstEnergy in 2011 compared to 2010. The decrease resulted primarily from decreased capitalized interest and increased depreciation expense resulting from the completed construction projects placed into service ($58 million), decreased investment income ($16 million), an asset impairment charge in the first quarter of 2011 ($11 million) and higher income taxes ($13 million).
Summary of Results of Operations — 2010 Compared with 2009
Financial results for FirstEnergy’s major business segments in 2010 and 2009 were as follows:


64


2010 Financial Results Regulated Distribution Competitive Energy Services Regulated Independent Transmission Other and Reconciling Adjustments FirstEnergy Consolidated
  (In millions)
Revenues:          
External          
Electric $9,271
 $3,252
 $—
 $—
 $12,523
Other 300
 323
 242
 (123) 742
Internal 139
 2,301
 —
 (2,366) 74
Total Revenues 9,710
 5,876
 242
 (2,489) 13,339
           
Operating Expenses:          
Fuel —
 1,432
 —
 —
 1,432
Purchased power 5,273
 1,724
 —
 (2,373) 4,624
Other operating expenses 1,320
 1,393
 61
 (78) 2,696
Pensions and OPEB mark-to-market adjustment 82
 107
 (2) 3
 190
Provision for depreciation 433
 284
 37
 14
 768
Amortization of regulatory assets, net 712
 —
 10
 —
 722
General taxes 605
 124
 30
 17
 776
Impairment of long-lived assets —
 388
 —
 —
 388
Total Operating Expenses 8,425
 5,452
 136
 (2,417) 11,596
           
Operating Income 1,285
 424
 106
 (72) 1,743
           
Other Income (Expense):          
Investment income 102
 51
 —
 (36) 117
Interest expense (500) (232) (22) (91) (845)
Capitalized interest 4
 95
 2
 64
 165
Total Other Expense (394) (86) (20) (63) (563)
           
Income Before Income Taxes 891
 338
 86
 (135) 1,180
Income taxes 338
 128
 32
 (36) 462
Net Income 553
 210
 54
 (99) 718
Loss attributable to noncontrolling interest —
 —
 —
 (24) (24)
Earnings available to FirstEnergy Corp. $553
 $210
 $54
 $(75) $742



65


2009 Financial Results Regulated Distribution Competitive Energy Services Regulated Independent Transmission Other and Reconciling Adjustments FirstEnergy Consolidated
  (In millions)
Revenues:          
External          
Electric $10,585
 $1,447
 $—
 $—
 $12,032
Other 331
 481
 223
 (111) 924
Internal —
 2,843
 —
 (2,826) 17
Total Revenues 10,916
 4,771
 223
 (2,937) 12,973
           
Operating Expenses:          
Fuel —
 1,153
 —
 —
 1,153
Purchased power 6,560
 996
 —
 (2,826) 4,730
Other operating expenses 1,257
 1,332
 56
 (94) 2,551
Pensions and OPEB mark-to-market adjustment 166
 151
 2
 2
 321
Provision for depreciation 426
 279
 37
 15
 757
Amortization of regulatory assets, net 1,006
 —
 13
 —
 1,019
General taxes 589
 112
 32
 20
 753
Impairment of long-lived assets —
 6
 —
 —
 6
Total Operating Expenses 10,004
 4,029
 140
 (2,883) 11,290
           
Operating Income 912
 742
 83
 (54) 1,683
           
Other Income (Expense):          
Investment income 141
 121
 —
 (58) 204
Interest expense (478) (174) (19) (307) (978)
Capitalized interest 3
 62
 1
 65
 131
Total Other Expense (334) 9
 (18) (300) (643)
           
Income Before Income Taxes 578
 751
 65
 (354) 1,040
Income taxes 243
 305
 26
 (390) 184
Net Income 335
 446
 39
 36
 856
Loss attributable to noncontrolling interest —
 —
 —
 (16) (16)
Earnings available to FirstEnergy Corp. $335
 $446
 $39
 $52
 $872


66


Changes Between 2010 and 2009 Financial Results
Increase (Decrease)
 Regulated Distribution Competitive Energy Services Regulated Independent Transmission Other and Reconciling Adjustments FirstEnergy Consolidated
  (In millions)
Revenues:          
External          
Electric $(1,314) $1,805
 $—
 $—
 $491
Other (31) (158) 19
 (12) (182)
Internal 139
 (542) —
 460
 57
Total Revenues (1,206) 1,105
 19
 448
 366
           
Operating Expenses:          
Fuel —
 279
 —
 —
 279
Purchased power (1,287) 728
 —
 453
 (106)
Other operating expenses 63
 61
 5
 16
 145
Pensions and OPEB mark-to-market adjustment (84) (44) (4) 1
 (131)
Provision for depreciation 7
 5
 —
 (1) 11
Amortization of regulatory assets, net (294) —
 (3) —
 (297)
General taxes 16
 12
 (2) (3) 23
Impairment of long-lived assets —
 382
 —
 —
 382
Total Operating Expenses (1,579) 1,423
 (4) 466
 306
           
Operating Income 373
 (318) 23
 (18) 60
           
Other Income (Expense):          
Gain on partial sale of Signal Peak —
 —
 —
 —
 —
Investment income (39) (70) —
 22
 (87)
Interest expense (22) (58) (3) 216
 133
Capitalized interest 1
 33
 1
 (1) 34
Total Other Expense (60) (95) (2) 237
 80
           
Income Before Income Taxes 313
 (413) 21
 219
 140
Income taxes 95
 (177) 6
 354
 278
Net Income 218
 (236) 15
 (135) (138)
Loss attributable to noncontrolling interest —
 —
 —
 (8) (8)
Earnings available to FirstEnergy Corp. $218
 $(236) $15
 $(127) $(130)
Regulated Distribution — 2010 Compared with 2009
Net income increased by $218 million in 2010 compared to 2009, primarily due to CEI’s $216 million regulatory asset impairment in 2009 and lower pensions and OPEB costs, partially offset by increases in other operating expenses. Lower generation revenues were offset by lower purchased power expenses.


67


Revenues —
The decrease in total revenues resulted from the following sources:
Revenues by Type of Service 2010 2009 
Increase
(Decrease)
  (In millions)
Distribution services $3,629
 $3,419
 $210
Generation:      
Retail 4,457
 5,764
 (1,307)
Wholesale 702
 752
 (50)
Total generation sales 5,159
 6,516
 (1,357)
Transmission 596
 805
 (209)
Other 326
 176
 150
Total Revenues $9,710
 $10,916
 $(1,206)
The increase in distribution deliveries by customer class is summarized in the following table:
Electric Distribution MWH DeliveriesIncrease
Residential5.9%
Commercial2.8%
Industrial8.4%
Total Distribution MWH Deliveries5.6%
Higher deliveries to residential and commercial customers reflect increased weather-related usage due to a 70% increase in cooling degree days in 2010 compared to 2009, partially offset by a 4% decrease in heating degree days for the same period. In the industrial sector, MWH deliveries increased primarily to major automotive customers (16%), refinery customers (7%) and steel customers (38%). The increase in distribution service revenues also reflects Met-Ed's, Penelec's and Penn's recovery of the Pennsylvania EE&C 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 $1.4 billion decrease in generation revenues in 2010 compared to 2009:
Source of Change in Generation Revenues 
Increase
(Decrease)
  (In millions)
Retail:  
Effect of decrease in sales volumes $(1,435)
Change in prices 128
  (1,307)
Wholesale:  
Effect of decrease in sales volumes (64)
Change in prices 14
  (50)
Net Decrease in Generation Revenues $(1,357)
The decrease in retail generation sales volumes was primarily due to an increase in customer shopping in the Ohio Companies’ service territories. Total generation MWH provided by alternative suppliers as a percentage of total MWH deliveries by the Ohio Companies increased to 62% in 2010 from 17% in 2009.
The decrease in wholesale generation revenues reflected lower RPM revenues for Met-Ed and Penelec in the PJM market.
Transmission revenues decreased $209 million primarily due to the termination of the Ohio Companies’ transmission tariff effective June 1, 2009; transmission costs are now a component of the cost of generation established under the May 2009 Ohio CBP.
Other revenues increased by $150 million primarily due to Met-Ed's and Penelec's PSA with FES in 2010, resulting in increased capacity revenues.


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Operating Expenses —
Total operating expenses decreased by $1.6 billion due to the following:
Purchased power costs were $1.3 billion lower in 2010, largely due to lower volume requirements. 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 increase in customer shopping in the Ohio Companies’ service territories. The decrease in purchases from FES also resulted from the increase in customer shopping in Ohio.
An increase in purchased power unit costs from non-affiliates in 2010 resulted from higher capacity prices in the PJM market for Met-Ed and Penelec. A decrease in unit costs for purchases from FES was principally due to the lower weighted average unit price per MWH established under the May 2009 CBP auction for the Ohio Companies effective June 1, 2009.
Source of Change in Purchased Power 
Increase
(Decrease)
  (In millions)
Purchases from non-affiliates:  
Change due to increased unit costs $709
Change due to decreased volumes (1,489)
  (780)
Purchases from FES:  
Change due to decreased unit costs (257)
Change due to decreased volumes (250)
  (507)
Net Decrease in Purchased Power Costs $(1,287)
Transmission expenses increased $70 million primarily due to higher PJM network transmission expenses and congestion costs for Met-Ed and Penelec, partially offset by lower MISO network transmission expenses that are reflected in the generation rate established under the May 2009 Ohio CBP. Met-Ed and Penelec defer or amortize the difference between revenues from their transmission rider and transmission costs incurred, resulting in no material effect on current period earnings.
Energy efficiency program costs, which are also recovered through rates, increased $41 million in 2010 compared to 2009.
Labor and employee benefit expenses decreased by $30 million due to lower payroll costs resulting from staffing reductions implemented in 2009, and restructuring expenses recognized in 2009.
Pensions and OPEB mark-to-market adjustment charges decreased by $84 million primarily resulting from lower net actuarial losses.
Expenses for economic development commitments related to the Ohio Companies’ ESP were lower by $11 million in 2010 compared to 2009.
Depreciation expense increased $7 million due to property additions since 2009.
Amortization of regulatory assets decreased $294 million due primarily to the absence of the $216 million impairment of CEI’s regulatory assets in 2009, reduced net MISO and PJM transmission cost amortization and reduced CTC amortization for Met-Ed and Penelec, partially offset by increased amortization associated with the accelerated recovery of deferred distribution costs in Ohio and a $35 million regulatory asset impairment in 2010 associated with the Ohio Companies’ ESP and the absence of CEI’s purchased power cost deferrals that ended in early 2009.
General taxes increased $16 million principally due to a benefit relating to Ohio MWH excise taxes that was recognized in 2009 and applicable to prior years.
Other Expense —
Other expense increased $60 million in 2010 compared to 2009 primarily due to lower investment income on OE's and TE's nuclear decommissioning trusts ($37 million) and higher net interest expense associated with debt issuances during 2009 ($23 million).
Regulated Independent Transmission — 2010 Compared with 2009
Net income increased by $15 million in 2010 compared to 2009 due to increased revenues.


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Revenues —
Total revenues increased by $19 million principally due to higher peak loads in 2010 compared to 2009.
Operating Expenses —
Total operating expenses decreased by $4 million principally due to decreased property taxes and decreased pensions and OPEB costs primarily due to lower net actuarial losses.
Other Expense —
Other expense increased $2 million in 2010 due to higher interest expense associated with higher average debt levels in 2010 compared to 2009.
Competitive Energy Services — 2010 Compared to 2009
Net income decreased by $235 million in 2010 compared to 2009. The decrease in net income was primarily due to $382 million of impairment charges ($240 million net of tax) in 2010. In addition, FES sold a 6.65% participation interest in OVEC in 2010 compared to a 9% interest in 2009, accounting for $105 million of the reduction in net income. Investment income from nuclear decommissioning trusts was also lower in 2010. These reductions were partially offset by an increase in sales margins.
Revenues —
Total revenues increased $1.1 billion in 2010 compared to the same period in 2009 primarily due to an increase in direct and governmental aggregation sales and sales of RECs, partially offset by decreases in POLR sales to the Ohio Companies, other wholesale sales and the reduced OVEC participation interest sale in 2010.
The increase in reported segment revenues resulted from the following sources:
Revenues by Type of Service 2010 2009 Increase (Decrease)
  (In millions)
Direct and Governmental Aggregation $2,493
 $779
 $1,714
POLR 2,589
 2,863
 (274)
Wholesale 397
 632
 (235)
Transmission 77
 73
 4
RECs 74
 17
 57
Sale of OVEC participation interest 85
 252
 (167)
Other 161
 155
 6
Total Revenues $5,876
 $4,771
 $1,105
The increase in direct and governmental aggregation revenues of $1.7 billion resulted from increased revenue from the acquisition of new commercial and industrial customers as well as from new governmental aggregation contracts with communities in Ohio that provide generation to 1.5 million residential and small commercial customers at the end of 2010 compared to approximately 600,000 customers at the end of 2009. Increases in direct sales were partially offset by lower unit prices. Sales to residential and small commercial customers were also bolstered by summer weather in the delivery area that was significantly warmer than in 2009.
The decrease in POLR revenues of $274 million was due to lower sales volumes and lower unit prices to the Ohio Companies, partially offset by increased sales volumes and higher unit prices to Met-Ed and Penelec. The lower sales volumes and unit prices to the Ohio Companies in 2010 reflected the results of the May 2009 CBP. The increased revenues to Met-Ed and Penelec resulted from FES supplying volumes previously supplied through a third-party contract, and at prices that were slightly higher than in 2009.
Other wholesale revenues decreased $235 million due to reduced volumes, partially offset by higher prices. Lower sales volumes in MISO were due to available capacity serving increased retail sales in Ohio partially offset by increased sales under bilateral agreements in PJM.


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The following tables summarize the price and volume factors contributing to changes in revenues from generation sales:
Source of Change in Direct and Governmental Aggregation Increase (Decrease)
  (In millions)
Direct Sales:  
Effect of increase in sales volumes $1,080
Change in prices (87)
  993
Government Aggregation:  
Effect of increase in sales volumes 707
Change in prices 14
  721
Net Increase in Direct and Governmental Aggregation Revenues $1,714
Source of Change in Wholesale Revenues Increase (Decrease)
  (In millions)
POLR:  
Effect of increase in sales volumes $38
Change in prices (312)
  (274)
Other Wholesale:  
Effect of decrease in sales volumes (344)
Change in prices 109
  (235)
Net Decrease in Wholesale Revenues $(509)
Operating Expenses —
Total operating expenses increased $1.4 billion in 2010 due to the following factors:
Fuel costs increased $279 million in 2010 compared to 2009 primarily due to increased volumes consumed ($217 million) and higher unit prices ($62 million). The higher volumes consumed in 2010 were due to increased sales to direct and governmental aggregation customers, improved economic conditions and improved generating unit availability. The increase in unit prices was due primarily to increased coal transportation costs and to higher nuclear fuel unit prices following the refueling outages that occurred in 2009 and 2010.
Purchased power costs increased $728 million. Increased volumes purchased primarily relate to the assumption of a 1,300 MW third party contract from Met-Ed and Penelec.
Fossil operating costs decreased $12 million due primarily to lower labor and professional and contractor costs, which were partially offset by reduced gains from the sale of emission allowances and excess coal.
Nuclear operating costs decreased $21 million due primarily to lower labor, consulting and contractor costs partially offset by increased nuclear property insurance and employee benefit costs. The year 2010 had one less refueling outage and fewer extended outages than the same period of 2009.
Transmission expenses increased $25 million due primarily to increased costs in MISO of $170 million from higher network, ancillary and congestion costs, partially offset by lower PJM transmission expenses of $145 million due to lower congestion costs.
Depreciation expense increased $5 million principally due to property additions that were placed in service since 2009.
General taxes increased $12 million due to an increase in revenue-related taxes.
Other operating expenses increased $406 million primarily due to a $382 million impairment charge ($240 million net of tax) related to operational changes at certain smaller coal-fired units. Expenses also increased for professional and contractor services, billings from affiliated service companies, uncollectible customer accounts and agent fees, as FES continued to grow its retail business.


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Other Expense —
Total other expense in 2010 was $95 million higher than the same period in 2009, primarily due to a $66 million decrease in nuclear decommissioning trust investment income and a $25 million increase in net interest expense from new long-term debt issued in late 2009 combined with the restructuring of outstanding PCRBs that occurred throughout 2009 and 2010.
Other — 2010 Compared to 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 $127 million decrease in earnings available to FirstEnergy in 2010 compared to 2009. The decrease resulted primarily from increased income tax expense ($354 million) due in part to the absence of favorable tax settlements that occurred in 2009 ($200 million), partially offset by the absence of 2009 debt retirement costs in connection with the tender offer for holding company debt ($90 million),decreased interest expense associated with the debt retirement ($53 million) and increased investment income ($22 million).
CAPITAL RESOURCES AND LIQUIDITY

As of JanuaryDecember 31, 2010 we2011, FirstEnergy had commitments$202 million of approximately $3.4 billion of liquidity including a $2.75 billion revolving credit facility, a $100 million bank linecash and cash equivalents available to FESfund investments, operations and $515 million of accounts receivable financing facilities through our Ohio and Pennsylvania utilities. We expect ourcapital expenditures.
FirstEnergy expects its existing sources of liquidity to remain sufficient to meet ourits anticipated obligations and those of ourits subsidiaries. OurFirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. During 2009In addition to internal sources to fund liquidity and in subsequent years, we expectcapital requirements for 2012 and beyond, FirstEnergy expects to satisfy theserely on external sources of funds. Short-term cash requirements with a combination ofnot met by cash provided from operations and funds from the capital markets as market conditions warrant. We also expectare generally satisfied through short-term borrowings. Long-term cash needs may be met through issuances of debt and/or equity securities. FirstEnergy expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements during those periods.along with continued access to long-term capital markets.

A material adverse change in operations, or in the availability of external financing sources, could impact FirstEnergy’s liquidity position and ability to fund its capital requirements. To mitigate risk, FirstEnergy’s business strategy stresses financial discipline and a strong focus on execution. Major elements include the expectation of: adequate cash from operations, opportunities for favorable long-term earnings growth in the competitive generation markets, operational excellence, business plan execution, well-positioned generation fleet, no speculative trading operations, appropriate long-term commodity hedging positions, manageable capital expenditure program, adequately funded pension plan, minimal near-term maturities of existing long-term debt, commitment to a secure dividend and a successful merger integration.
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As of December 31, 2009, our2011, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was principally due to short-term borrowings ($1.2 billion) and the classification of certain variable interest rate PCRBs as currently payable long-term debt. Currently payable long-term debt, which, as of December 31, 2009,2011, included the following (in millions):following:
Currently Payable Long-term Debt (In millions)
Met-Ed, Penelec, FGCO and NGC PCRBs supported by bank LOCs (1)
 $632
AE Supply unsecured note 503
FGCO and NGC unsecured PCRBs (1)
 270
WP unsecured note 80
NGC collateralized lease obligation bonds 67
Sinking fund requirements 52
Other notes 17
  $1,621
(1)
These PCRBs are classified as currently payable long-term debt solely because the applicable Interest rate mode permits individual debt holders to put the respective debt back to the issuer prior to maturity.


Currently Payable Long-term Debt   
PCRBs supported by bank LOCs(1)
 $1,553 
FGCO and NGC unsecured PCRBs(1)
 15 
Met-Ed unsecured notes(2)
 100 
Penelec FMBs(3)
 24 
NGC collateralized lease obligation bonds 45 
Sinking fund requirements 34 
Other notes(3)
 63 
  $1,834 
    
(1)  Interest rate mode permits individual debt holders to put the respective debt back to the issuer prior to maturity.
(2)  Mature in March 2010.
(3)  Mature in November 2010.
 
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Short-Term Borrowings

WeFirstEnergy had approximately $1.2 billion ofnosignificant short-term borrowings as of December 31, 20092011, and $2.4 billion short-term borrowings of approximately $700 millionas ofDecember 31, 2008. Our2010. FirstEnergy’s available liquidity as of January 31, 2010, is summarized in the following table:2012, was as follows:

Company Type Maturity Commitment  
Available
Liquidity as of
January 31, 2010
  Type Maturity Commitment Available Liquidity
     (In millions)  (In millions)
FirstEnergy(1)
 Revolving Aug. 2012 $2,750  $1,387  Revolving June 2016 $2,000
 $1,395
FirstEnergy Solutions Bank line Mar. 2011  100   - 
Ohio and Pennsylvania Companies Receivables financing 
Various(2)
  515   308 
FES / AE Supply Revolving June 2016 2,500
 2,498
TrAIL Revolving Jan. 2013 450
 450
AGC Revolving Dec. 2013 50
 —
   Subtotal $3,365  $1,695  Subtotal $5,000
 $4,343
   Cash  -   764  Cash —
 49
   Total $3,365  $2,459  Total $5,000
 $4,392

(1)
FirstEnergy Corp. and subsidiary borrowers.
(2)$370 million expires February 22, 2010; $145 million expires December 17, 2010. The Ohio and Pennsylvania Companies have typically renewed expiring receivables facilities on an annual basis and expect to continue that practice as market conditionsFE and the continued quality of receivables permit.Utilities

Revolving Credit FacilityFacilities
FirstEnergy and FES / AE Supply Facilities
We have the capabilityFirstEnergy and certain of its subsidiaries participate in two five-year syndicated revolving credit facilities with aggregate commitments of$4.5 billion(Facilities).
An aggregate amount of$2 billionis available to request an increase in the total commitments availablebe borrowed under the $2.75 billiona syndicated revolving credit facility (included in the borrowing capability table above) up to a maximum of $3.25 billion,(FirstEnergy Facility), subject to separate borrowing sublimits for each borrower. The borrowers under the discretion ofFirstEnergy Facility are FE, OE, Penn, CEI, TE, Met-Ed, ATSI, JCP&L, MP, Penelec, PE and WP. An additional$2.5 billionis available to be borrowed by FES and AE Supply under a separate syndicated revolving credit facility (FES/AE Supply Facility), subject to separate borrowing sublimits for each lender to provide additional commitments. borrower.
Commitments under each of the facility areFacilities will be available until August 24, 2012,June 17, 2016, unless the lenders agree, at the request of the applicable borrowers, to an unlimited number ofup to two additional one-year extensions. Generally, borrowings under each of the facility must be repaid within 364 days. Available amounts forFacilities are available to each borrower separately and mature on the earlier of364days from the date of borrowing or the commitment termination date, as the same may be extended.
Borrowings under each of the Facilities are subject to the usual and customary provisions for acceleration upon the occurrence of events of default, including a specified sub-limit,cross-default for other indebtedness in excess of$100 million, as well as applicable regulatory and other limitations.described further in Note 12, Capitalization.

The following table summarizes the borrowing sub-limits for each borrower under the facility,Facilities, 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 ofDecember 31, 2009:2011:


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76

Borrower
 
Revolving
Credit Facility
Sub-Limit
  
Regulatory and
Other Short-Term
Debt Limitations
  Revolving Credit Facility Sub-Limit Regulatory and Other Short-Term Debt Limitations 
 (In millions)  (In millions) 
FirstEnergy $2,750  $-(1)
FE $2,000
 —
(1) 
FES  1,000   -(1) $1,500
 —
(2) 
AE Supply $1,000
 —
(2) 
OE  500   500  $500
 $500
 
Penn  50   33(2)
CEI  250(3)  500  $500
 $500
 
TE  250(3)  500  $500
 $500
 
JCP&L  425   411(2) $425
 $411
(3) 
Met-Ed  250   300(2) $300
 $300
(3) 
Penelec  250   300(2) $300
 $300
(3) 
West Penn $200
 $200
(3) 
MP $150
 $150
(3) 
PE $150
 $150
(3) 
ATSI  50(4)  50  $100
 $100
 
        
(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 ATSI has received regulatory approval to have short-term borrowings up to the same amount.
 
Penn $50
 $33
(3) 
(1)
No limitations.
(2)
No limitation based upon blanket financing authorization from the FERC under existing open market tariffs.
(3)
Excluding amounts which may be borrowed under the regulated companies’ money pool.

UnderThe entire amount of the revolving credit facility, borrowers may requestFES/AE Supply Facility and$700 millionof the FirstEnergy Facility, subject to each borrower’s sub-limit, is available for 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 each of the facilityFacilities and against the applicable borrower'sborrower’s borrowing sub-limit.

The revolving credit facilityEach of the Facilities 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 December 31, 2009, our2011, FirstEnergy’s and its subsidiaries’ debt to total capitalization ratios (as defined under each of the revolving credit facility)Facilities) were as follows:

Borrower 
FirstEnergy(1)
61.557.5%
FES54.851.4%
OE51.363.4%
Penn35.542.8%
CEI59.759.4%
TE60.862.7%
JCP&L35.643.6%
Met-Ed41.256.0%
Penelec53.656.6%
ATSI48.6%
MP48.856.6%
PE56.8%
WP52.1%
AE Supply38.5%

(1)As of December 31, 2009, FirstEnergy could issue additional debt of approximately $2.5 billion, or recognize a reduction in equity of approximately $1.4 billion, and remain within the limitations of the financial covenants required by its revolving credit facility.
As of December 31, 2011, FirstEnergy could issue additional debt of approximately $6.7 billion, or recognize a reduction in equity of approximately $3.6 billion, and remain within the limitations of the financial covenants required by its revolving credit facility.
The revolving credit facility doesFacilities do not contain provisions that either restrict the ability to borrow or accelerate repaymentpayment of outstanding advances as a result of any change in credit ratings. Pricing is defined in "pricingsubject to “pricing grids,"” whereby the borrower's cost of funds borrowed under the facilityFacilities is related to the credit ratings of the company borrowing the funds.


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AGC and TrAIL Revolving Credit Facilities
FirstEnergy also has established$500 millionof revolving credit facilities that are available to TrAIL ($450 million) and AGC($50 million) until January 2013 and December 2013, respectively.
Under the terms of its credit facility, outstanding debt of AGC may not exceed 65% of the sum of its debt and equity as of the last day of each calendar quarter. Outstanding debt for TrAIL may not exceed 65% of the sum of its debt and equity as of the last day of each calendar quarter through December 31, 2012. These provisions limit debt levels of these subsidiaries and also limit the net assets of each subsidiary that may be transferred to AE. As of December 31, 2011, the debt to total capitalization ratios for TrAIL and AGC (as defined under each of their credit facilities) were 48% and 51%, respectively.

As of December 31, 2011, TrAIL could issue additional debt of approximately $222 million, or recognize a reduction in equity of approximately $341 million and AGC could issue additional debt of approximately $39 million, or recognize a reduction in equity of approximately $61 million, and remain within the limitations of the financial covenants required by their credit facilities.
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 2009during 2011 was 0.72%0.44% per annum for the regulated companies'companies’ money pool and 0.90%0.42% per annum for the unregulated companies'companies’ money pool.

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Pollution Control Revenue Bonds

As of December 31, 2009, our2011, FirstEnergy’s currently payable long-term debt included approximately $1.6 billion$632 million (FES - $1.5 billion,— $558 million, 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 ourFirstEnergy variable interest rate PCRBs were issued by the following banks:banks as of December 31, 2011:

 Aggregate LOC   Reimbursements of
LOC Bank 
Amount(3)
 LOC Termination Date LOC Draws Due 
Aggregate LOC
Amount(1)
 LOC Termination Date 
Reimbursements
of LOC Draws Due
 (In millions)     (In millions) 
UBS $272
 April 2014 April 2014
CitiBank N.A. $166 June 2014 June 2014 165
 June 2014 June 2014
Wachovia Bank 153
 March 2014 March 2014
The Bank of Nova Scotia  284 Beginning April 2011 
Multiple dates(4)
 49
 April 2014 
Multiple dates(2)
The Royal Bank of Scotland  131 June 2012 6 months
KeyBank(1)
  237 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     $639
 

(1)Supported by four participating banks, with the LOC bank having 58% of the total commitment.
(2)Supported by 18 participating banks, with no one bank having more than 14% of the total commitment.
(1)
(3)Includes approximately $16$7 million of applicable interest coverage.
(4)
(2)
Shorter of 6 months or LOC termination date ($155 million) and shorter of one year or LOC termination date ($129 million).date.

In 2009, holders ofDuring 2011, FirstEnergy redeemed or repurchased approximately $434$520.4 million of LOC-supported PCRBs of OE and NGC were notified that the applicable Wachovia Bank LOCs were set to expire. 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. FGCO remarketed $100 million of those PCRBs, which were previously held by OE and NGC and 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. Also during 2009, FGCO and NGC remarketed approximately $329 million of other PCRBs supported by LOCs set to expire in 2009. Those PCRBs were also remarketed in fixed interest rate modes and secured by FMBs, thereby eliminating the need for third-party credit support. 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 tosummarized in the applicable trustee under six separate series of PCRBs. On August 14, 2009, $177following table. Approximately $28.5 million of non-LOC supported fixed rateFGCO FMBs and $98.9 million of NGC FMBs associated with the PCRBs were issued and sold on behalf of FGCO to pay a portion ofreturned for cancellation by the cost of acquiring, constructing and installing air quality facilities at its W.H. Sammis Generating Station.associated LOC providers.
SubsidiariesAmount 
 (In millions) 
AE Supply$53.0
(1) 
FGCO$198.2
(2) 
NGC$213.5
(2) 
MP$70.2
(1) 
(1)
Includes $14.4 million of PCRBs redeemed for which MP and AE Supply are co-obligors.
(2)
Subject to market conditions, these PCRBs are being held for future remarketing.


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Long-Term Debt Capacity

As ofDecember 31, 2009,2011, the Ohio Companies and Penn had the aggregate capability to issue approximately $1.4$2.7 billionof 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 $127$232 millionand $36$20 million, respectively, as of December 31, 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.respectively. As a result, the provisions for TE to incur additional secured debt do not apply.

Based upon FGCO's FMB indenture, net earnings and available bondable property additions as of December 31, 2009, FGCO had the capability to issue $2.2 billion of additional FMBs under the terms of that indenture. On June 16, 2009, FGCO issued a total of approximately $395.9 million principal amount of FMBs, of which $247.7 million related to three new refunding series of PCRBs and approximately $148.2 million related to amendments to existing LOC and reimbursement agreements supporting two other series of PCRBs. On June 30, 2009, FGCO issued a total of approximately $52.1 million principal amount of FMBs related to three existing series of PCRBs (repurchased in October 2009, as described above).

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In June 2009, a new FMB indenture became effective for NGC. 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 PSA 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. Based upon NGC’s FMB indenture net earnings and available bondable property additions, NGC had the capability to issue $294 million ofprovisions, TE cannot incur any additional FMBs as of December 31, 2009.

secured debt. Met-Ed and Penelec had the capability to issue secured debt of approximately $379$376 millionand $319$382 million, respectively, under provisions of their senior note indentures as ofDecember 31, 2009.2011. In addition, based upon their respective FMB indentures, net earnings and available bondable property additions as ofDecember 31, 2011, MP, PE and WP had the capability to issue approximately$1.1 billionof additional FMBs in the aggregate. These companies may be further limited by the financial covenants of the Facilities and subject to current regulatory approvals and applicable statutory and/or charter limitations.

Based upon FGCO’s net earnings and available bondable property additions under its FMB indentures as ofDecember 31, 2011, FGCO had the capability to issue$2.1 billionof additional FMBs under the terms of that indenture. Based upon NGC’s net earnings and available bondable property additions under its FMB indenture as ofDecember 31, 2011, NGC had the capability to issue$2.0 billionof additional FMBs under the terms of that indenture.
FirstEnergy'sFirstEnergy’s access to capital markets and costs of financing are influenced by the credit ratings of its securities. The following table displays FirstEnergy's, FES' and the Utilities' securities ratings as of February 11, 2010. On February 11, 2010,March 21, 2011, S&P issued a report lowering FirstEnergy’s and its subsidiaries’ credit ratings by one notch, while maintaining its stable outlook. As a result, FirstEnergy may be required to post up to $48 million of collateral (see Note 15(B)). Moody's and Fitch affirmed the ratings and stable outlook of FirstEnergy and its subsidiaries. On May 27, 2011, Fitch upgraded ratings for certain subsidiaries onand revised the outlook to stable from negative for FirstEnergy and FES. On August 18, 2011, Moody's downgraded ratings for FES to Baa3 from Baa2 and revised FES' outlook to stable. On January 18, 2012, Moody's upgraded ratings for TrAIL to A3 from Baa2. The following table displays FirstEnergy’s and its subsidiaries’ debt credit ratings as of February 11, 2010.24, 2012:

 Senior SecuredSenior Unsecured
IssuerS&PMoodysS&PMoodysMoody’sFitchS&PMoody’sFitch
FirstEnergy Corp.FE--———BB+Baa3
 BBB
FES 
FirstEnergy Solutions—--——BBB-Baa2
Baa3 BBB
AE Supply 
Ohio Edison—BBBA3——BBB-Baa2
Baa3 BBB-
AGC 
Cleveland Electric Illuminating—BBBBaa1——BBB-Baa3
 
Toledo EdisonBBBBaa1--
Pennsylvania PowerBBB+A3--
Jersey Central Power & Light--BBB-Baa2
Metropolitan EdisonBBBA3BBB-Baa2
Pennsylvania ElectricBBBA3BBB-Baa2
ATSI--———BBB-Baa1A-
CEIBBBBaa1BBBBBB-Baa3BBB-
JCP&L———BBB-Baa2BBB+
Met-EdBBBA3A-BBB-Baa2BBB+
MPBBB+Baa1A-BBB-Baa3BBB+
OEBBBA3BBB+BBB-Baa2BBB
PenelecBBBA3BBB+BBB-Baa2BBB
PennBBB+A3BBB+———
PEBBB+Baa1A-BBB-Baa3BBB+
TEBBBBaa1BBB———
TrAIL———BBB-A3A-
WPBBB+A3A-BBB-Baa2BBB+

On September 22, 2008, FirstEnergy, along withSee Note 12, Capitalization of the Shelf Registrants, filed an automatically effective shelf registration statement withCombined Notes to the SECConsolidated Financial Statements for an unspecified numberadditional information on FirstEnergy's and amountthe Registrants' long-term debt and other long-term obligations that were outstanding as 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.December 31, 2011.

Changes in Cash Position

As of December 31, 2009, we2011, FirstEnergy had $874$202 million in of cash and cash equivalents compared to $545 millionapproximately $1 billion 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.2010. As of December 31, 20092011 and 2008,2010, FirstEnergy had approximately $12$79 million and $17$13 million, respectively, of restricted cash included in other current assets on the Consolidated Balance Sheet.

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During 2009, we2011, FirstEnergy received $972 million$1.8 billion of cash dividends from ourits subsidiaries and paid $670$881 millionin cash dividends to common shareholders. There are no material restrictions on the payment of cash dividendsshareholders, including $20 million paid in March by our subsidiaries. In additionAE to paying dividends from retained earnings, each of our electric utility subsidiaries has authorization from the FERC to pay cash dividends from paid-in capital accounts, as long as its 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.former shareholders.


76


Cash Flows fromFrom Operating Activities

OurFirstEnergy’s consolidated net cash from operating activities is provided primarily by our energy delivery servicesits regulated distribution, regulated independent transmission and competitive energy services businesses (see Results of Operations above). Net cash provided from operating activities was $2.5$3.1 billion in 2009, $2.22011, $3.1 billion in 20082010 and $1.7$2.5 billion in 2007,2009, as summarized in the following table:

 2009  2008  2007 
 (In millions) 
Operating Cash Flows 2011 2010 2009
 (In millions)
Net income $990  $1,339  $1,312  $869
 $718
 $856
Non-cash charges and other adjustments  2,281   1,405   670 
Pension trust contribution  (500)  -   (300)
Non-cash charges 2,424
 2,343
 2,095
Pension trust contributions (372) —
 (500)
Working capital and other  (306)  (520)  17  142
 15
 14
 $2,465  $2,224  $1,699  $3,063
 $3,076
 $2,465

Net cash provided from operating activities increased by $241 million in 2009 primarily due to anThe 2011 increase in non-cash charges is primarily due to increased pensions and other adjustmentsOPEB mark-to-market adjustment charges from higher actuarial losses ($317 million), increased deferred taxes resulting from bonus depreciation ($348 million) and increased depreciation attributable to the acquired Allegheny companies ($353 million). These increases were partially offset by gains from the sale of $876assets, mostly due to the sale of Signal Peak ($543 million), and anlower amortization of regulatory assets from reduced net PJM transmission cost and transition cost recovery ($393 million).
The 2011 increase in cash flows from working capital and other of $214, partially offset by a $500 million pension trust contribution in 2009 and a $349 million decrease in net income (see Results of Operations above).

The increase in non-cash charges and other adjustments is primarily due to decreased receivables from higher net amortization of regulatory assets ($282 million), including CEI’s $216customer collections ($324 million regulatory asset impairment, an increase in the provision for depreciation ($59 million) and the modification of certain purchased power contracts that resulted in a mark-to-market charge of approximately $205 million (see Note 6). Also included in non-cash charges and other adjustments was a $146 million charge relating to debt redemptions in 2009, of which $123 million was related primarily to premiums paid and included as a cash outflow in financing activities. The changes in working capital and other primarily resulted from a $268 million decrease in prepaid taxes due to decreased tax payments.

Net cash provided from operating activities increased in 2008 compared to 2007 due to an increase in non-cash charges primarily due to lower deferrals of new regulatory assets and purchased power costs and higher deferred income taxes. The deferral of new regulatory assets decreased primarily as a result of the Ohio Companies’ transmission and fuel recovery riders that became effective in July 2007 and January 2008, respectively, and) partially offset by the absence of the deferral of decommissioning costs related to the Saxton nuclear research facilityinterest rate swap activity transacted in the first quarter of 2007. Lower deferrals of purchased power costs reflected an increase in the market value of NUG power. The change in deferred income taxes is primarily due to additional tax depreciation under the Economic Stimulus Act of 2008, the settlement of tax positions taken on federal returns in prior years, and the absence of deferred income taxes related to the Bruce Mansfield Unit 1 sale and leaseback transaction in 2007. The changes in working capital and other primarily resulted from changes in accrued taxes of $1102010 ($129 million and prepaid taxes of $278 million, primarily due to increased tax payments. Changes in materials and supplies of $131 million resulted from higher fossil fuel inventories and were partially offset by changes in receivables of $107 million.

).
Cash Flows From Financing Activities

In 2009, net2011, cash provided fromused for financing activities was $49$2,924 million compared to $1.2 billion$983 million in 2008. The decrease was primarily due to increased long-term debt redemptions ($1.6 billion) and increased repayments on short-term borrowings ($2.7 billion), partially offset by increased long-term debt issuances in 2009 ($3.3 billion)2010. The increased long-term debt redemptions were primarily due to the $1.2 billion tender offer for holding company notes completed by FirstEnergy in September 2009, including approximately $122 million of premiums and redemption expenses paid. The short-term repayments in 2009 were primarily due to net repayments on the $2.75 billion revolving credit facility (see Revolving Credit Facility above) compared to net borrowings on the facility in 2008. The following table summarizessecurity issuances (net of any discounts) and redemptions, including premiums paid to debt holders as a result of the tender offer.

redemptions:
80
Securities Issued or         
Redeemed / Repurchased 2009  2008  2007 
  (In millions) 
New issues         
First mortgage bonds $398  $592  $- 
Pollution control notes  940   692   427 
Senior secured notes  297   -   - 
Unsecured notes  2,997   83   1,093 
  $4,632  $1,367  $1,520 
Redemptions            
First mortgage bonds $1  $126  $293 
Pollution control notes  884   698   436 
Senior secured notes  217   35   188 
Unsecured notes  1,508   175   153 
Common stock  -   -   969 
  $2,610  $1,034  $2,039 
             
Short-term borrowings (repayments), net $(1,246) $1,494  $(205)

The following table summarizes new debt issuances, excluding any premium or discounts, (excluding PCRB issuances and refinancings of $940 million) during 2009.

Issuing Company
Issue
Date
 
Principal
(in millions)
 
Type
 
Maturity
 
         
Met-Ed*01/20/2009 $300 7.70% Senior Notes  2019 
           
JCP&L*01/27/2009 $300 7.35% Senior Notes  2019 
           
TE*04/24/2009 $300 7.25% Senior Secured Notes  2020 
           
Penn06/30/2009 $100 6.09% FMB  2022 
           
FES08/07/2009 $400 4.80% Senior Notes  2015 
   $600 6.05% Senior Notes  2021 
   $500 6.80% Senior Notes  2039 
           
CEI*08/18/2009 $300 5.50% FMB  2024 
           
Penelec*09/30/2009 $250 5.20% Senior Notes  2020 
   $250 6.15% Senior Notes  2038 
           
ATSI12/15/2009 $400 5.25% Senior Notes  2022 
           
* Issued under the shelf registration statement referenced above. 

Securities Issued or Redeemed 2011 2010 2009
    (In millions)  
New Issues      
PCRBs $272
 $740
 $940
Long-term revolving credit 70
 —
 —
Senior secured notes —
 350
 297
FMBs —
 —
 398
Unsecured Notes 262
 9
 2,997
  $604
 $1,099
 $4,632
Redemptions      
PCRBs $792
 $741
 $884
Long-term revolving credit 495
 —
 —
Senior secured notes 460
 141
 217
FMBs 15
 32
 1
Unsecured notes 147
 101
 1,508
  $1,909
 $1,015
 $2,610
       
Net repayment of short-term borrowings $(700) $(378) $(1,246)
Cash Flows fromFrom Investing Activities

Net cash flowsCash used infor investing activities in 2011resulted principally from cash used for property additions. Additions for the energy delivery services segment primarily include expenditures related to transmission and distribution facilities. Capital spendingadditions, partially offset by the competitive energy services segment is principally generation-related.cash acquired in the Allegheny merger and proceeds from asset sales. The following table summarizes investing activities for the three years ended December 31, 2011, 2010 and 2009 by business segment:


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81
Summary of Cash Flows
Provided from (Used for) Investing Activities
 
Property
Additions
 Investments Other Total
    (In millions)  
Sources (Uses)        
2011        
Regulated distribution $(1,060) $30
 $(83) $(1,113)
Competitive energy services (927) 545
 3
 (379)
Regulated independent transmission (192) —
 (3) (195)
Cash received in Allegheny merger —
 590
 —
 590
Other and reconciling adjustments (99) 223
 17
 141
Total $(2,278) $1,388
 $(66) $(956)
         
2010        
Regulated distribution $(681) $96
 $17
 $(568)
Competitive energy services (1,159) (43) (51) (1,253)
Regulated independent transmission (64) —
 (4) (68)
Other and reconciling adjustments (59) (30) 30
 (59)
Total $(1,963) $23
 $(8) $(1,948)
         
2009        
Regulated distribution $(718) $39
 $(45) $(724)
Competitive energy services (1,412) (8) (19) (1,439)
Regulated independent transmission (32) —
 (1) (33)
Other and reconciling adjustments (41) (27) 79
 11
Total $(2,203) $4
 $14
 $(2,185)
Summary of Cash Flows Provided from Property          
(Used for) Investing Activities Additions  Investments  Other  Total 
Sources (Uses) (In millions) 
2009            
Energy delivery services
 $(750) $39  $(46) $(757)
Competitive energy services
  (1,262)  (8)  (19)  (1,289)
Other
  (149)  (3)  72   (80)
Inter-Segment reconciling items
  (42)  (24)  7   (59)
Total
 $(2,203) $4  $14  $(2,185)
                 
2008
                
Energy delivery services
 $(839) $(41) $(17) $(897)
Competitive energy services
  (1,835)  (14)  (56)  (1,905)
Other
  (176)  106   (61)  (131)
Inter-Segment reconciling items
  (38)  (12)  -   (50)
Total
 $(2,888) $39  $(134) $(2,983)
                 
2007
                
Energy delivery services
 $(814) $53  $(6) $(767)
Competitive energy services
  (740)  1,300   -   560 
Other
  (21)  2   (14)  (33)
Inter-Segment reconciling items
  (58)  (15)  -   (73)
Total
 $(1,633) $1,340  $(20) $(313)

Net cash used for investing activities in 20092011 decreased by $798$992 million compared to 2008.2010. The changedecrease was principally due to a $685 million decrease in property additions, which reflects lower AQC system expenditures and the absence in 2009 of the purchase of certain lessor equity interests in Beaver Valley Unit 2 and Perry and the purchase of the partially-completed Fremont Energy Center. Net cash used for other investing activities decreased primarily due to the liquidation of restricted funds used for debt redemptions in 2009 combined with decreased cash investmentsacquired in the Signal Peak coal mining project in 2009 as compared to 2008.

Net cash used for investing activities in 2008 increased by $2.7 billion compared to 2007. The change was principally due to a $1.3 billionAllegheny merger ($590 million) and an increase in property additions and the absence of $1.3 billion of cash proceeds from the Bruce Mansfield Unit 1 sale and leaseback transaction that occurred in the third quarter of 2007. Theasset sales ($723 million), partially offset by increased property additions reflected the acquisitions described above and higher planned AQC system expenditures in 2008. Cash used for other investing activities increased primarily as a result of the 2008 investments in the Signal Peak coal mining project and future-year emission allowances.($315 million).

Our capital spending for 2010 is expected to be approximately $1.7 billion (excluding nuclear fuel), of which $241 million relates to AQC system expenditures. Capital spending for 2011 and 2012 is expected to be approximately $1.0$2.1 billion(excluding nuclear fuel).For 2013, we anticipate baseline capital expenditures of approximately $2.0 billion, which exclude any potential additional strategic opportunities, future mandated spending, energy efficiency or environmental spending relating to $1.2 billion each year. MATS. Planned capital initiatives are intended to promote reliability, improve operations, and support current environmental and energy efficiency directives.Our capital spending investments for additional nuclear fuel during 2010 is estimatedare expected to be approximately $170 million.$280 million and $219 million in 2012 and 2013, respectively.

CONTRACTUAL OBLIGATIONS

As of December 31, 2009,2011, our estimated cash payments under existing contractual obligations that we consider firm obligations are as follows:

        2011-   2013-    
Contractual Obligations Total  2010   2012   2014  Thereafter  Total 2012 2013-2014 2015-2016 Thereafter
 (In millions)  (In millions)
Long-term debt $13,753  $264  $433  $1,084  $11,972 
Short-term borrowings  1,181   1,181   -   -   - 
Long-term debt(1)
 $17,005
 $1,605
 $2,192
 $2,688
 $10,520
Interest on long-term debt (1)(2)
  11,663   785   1,537   1,473   7,868  12,071
 975
 1,804
 1,548
 7,744
Operating leases (2)(3)
  3,485   225   442   459   2,359  3,147
 258
 492
 598
 1,799
Fuel and purchased power (3)(4)
  18,422   3,217   4,753   4,245   6,207  32,877
 3,598
 5,589
 4,616
 19,074
Capital expenditures  999   335   376   245   43  2,715
 681
 984
 638
 412
Pension funding  972   -   63   557   352  1,030
 —
 231
 799
 —
Other (4)(5)
  283   232   3   2   46  263
 28
 105
 47
 83
Total $50,758  $6,239  $7,607  $8,065  $28,847  $69,108
 $7,145
 $11,397
 $10,934
 $39,632

(1)
Excludes unamortized discounts and premiums and fair value accounting adjustments.
(2)
Interest on variable-rate debt based on rates as of December 31, 2009.2011.
(2)
(3)
See Note 76, Leases of the Combined Notes to the consolidated financial statements.Consolidated Financial Statements.
(3)
(4)
Amounts under contract with fixed or minimum quantities based on estimated annual requirements.
(4)
(5)
Includes amounts for capital leases (see Note 7)6, Leases of the Combined Notes to the Consolidated Financial Statements) and contingent tax liabilities (see Note 10)5, Taxes of the Combined Notes to the Consolidated Financial Statements).


78
82
Guarantees and Other Assurances


Excluded from the data shown above are estimates for the cash outlays stemming from power purchase contracts entered into by most of the Utilities and under which they procure the power supply necessary to provide generation service to their customers who do not choose an alternative supplier. The exact amounts will be determined by future customer behavior and consumption levels, but based on numerous planning assumptions, management estimates an amount of $5.4 billion in 2012, $1.8 billion of which relates to contracts with FES.
GUARANTEES AND OTHER ASSURANCES
As part of normal business activities, we enterFirstEnergy enters into various agreements on behalf of ourits subsidiaries to provide financial or performance assurances to third parties. These agreements include contractFirstEnergy guarantees surety bonds and LOCs. Some of the guaranteed contracts contain collateral provisions that are contingent upon either our or our subsidiaries’ credit ratings.

As of December 31, 2009, our maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $4.2 billion, as summarized below:

  Maximum 
Guarantees and Other Assurances
 
Exposure
 
  (In millions) 
FirstEnergy Guarantees of Subsidiaries:   
Energy and energy-related contracts (1)
 $382 
LOC (long-term debt) – interest coverage (2)
  6 
FirstEnergy guarantee of OVEC obligations  300 
Other (3)
  296 
   984 
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  2,464 
   2,601 
     
Surety Bonds:  101 
LOC (long-term debt) – interest coverage (2)
  3 
LOC (non-debt) (4)(5)
  502 
   606 
Total Guarantees and Other Assurances $4,191 

(1)Issued for open-ended terms, with a 10-day termination right by FirstEnergy.
(2)Reflects the interest coverage portion of LOCs issued in support of floating-rate PCRBs with various maturities. The principal amount of floating-rate PCRBs of $1.6 billion is reflected as currently payable long-term debt on FirstEnergy’s consolidated balance sheets.
(3)Includes guarantees of $80 million for nuclear decommissioning funding assurances and $161 million supporting OE’s sale and leaseback arrangement.
(4)Includes $167 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facility.
(5)Includes approximately $200 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $134 million pledged in connection with the sale and leaseback of Perry Unit 1 by OE.

We guarantee energy and energy-related payments of ourits subsidiaries involved in energy commodity activities principally to facilitate or hedge normal physical transactions involving electricity, gas, emission allowances and coal. WeFirstEnergy also provide guaranteesprovides credit support to various providers of credit support for the financing or refinancing by our subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements legally obligate us to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions include provisions for parent guarantees, surety bonds and/or financings where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, our guarantee enables the counterparty's legal claimLOCs to be satisfiedissued by our other assets. We believe the likelihood is remoteFirstEnergy on behalf of one or more of its subsidiaries. Additionally, certain contracts may contain collateral provisions that such parental guarantees will increase amounts otherwise paid by us to meet our obligations incurred in connection with ongoing energy and energy-related activities.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade to below investment grade, an acceleration of paymentcontingent upon either FirstEnergy's or funding obligation, or “material adverse event,” the immediate posting of cash collateral, provision of an LOC or accelerated payments may be required of the subsidiary. 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. As a result, FirstEnergy may be required to post up to $48 million of collateral. Moody's and Fitch affirmed the ratings and stable outlook of FirstEnergy and its subsidiaries on February 11, 2010. ratings.
As of December 31, 2009, our2011, FirstEnergy’s maximum exposure to potential future payments under these collateral provisions was $648 million, including the $48 million related to the credit rating downgrade by S&P on February 11, 2010,outstanding guarantees and other assurances approximated $3.7 billion, as shownsummarized below:

Guarantees and Other Assurances Maximum Exposure
  (In millions)
FirstEnergy Guarantees on Behalf of its Subsidiaries  
Energy and Energy-Related Contracts(1)
 $268
LOC (long-term debt) - interest coverage(2)
 5
OVEC obligations 300
Other(3)
 301
  874
   
Subsidiaries’ Guarantees  
Energy and Energy-Related Contracts 141
LOC (long-term debt) - interest coverage(2)
 2
FES’ guarantee of NGC’s nuclear property insurance 79
FES’ guarantee of FGCO’s sale and leaseback obligations 2,286
Other 12
  2,520
   
Surety Bonds 151
LOCs(4)
 189
  340
Total Guarantees and Other Assurances $3,734
(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 $632 million is reflected in currently payable long-term debt on FirstEnergy's consolidated balance sheets.
(3)
Includes guarantees of $95 million for nuclear decommissioning funding assurances, $161 million supporting OE’s sale and leaseback arrangement, and $36 million for railcar leases.
(4)
Includes $36 million issued for various terms pursuant to capacity available under FirstEnergy’s revolving credit facility, $116 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $37 million pledged in connection with the sale and leaseback of Perry by OE.
83
Collateral Provisions FES  Utilities  Total 
  
(In millions)
 
Credit rating downgrade to below investment grade
 $392  $115  $507 
Acceleration of payment or funding obligation
  45   53   98 
Material adverse event
  43   -   43 
Total
 $480  $168  $648 

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 $807 million, consisting of $51 million due to “material adverse event” contractual clauses, $98 million due to an acceleration of payment or funding obligation, and $658 million due to a below investment grade credit rating.

Most of ourFirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of$151 millionprovide 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.
While the types of guarantees discussed above are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a senior unsecured credit rating downgrade to below S&P's BBB- and Moody's Baa3 and lower, or a “material adverse event,” the immediate posting of collateral or accelerated payments may be required of the subsidiary. As ofDecember 31, 2011, FirstEnergy’s exposure to additional credit contingent contractual obligations was$636 million, as shown below:


In addition to guarantees and surety bonds, FES’79


Collateral Provisions FES AE Supply Utilities Total
  (In millions)
Credit rating downgrade to below investment grade (1)
 $468
 $8
 $57
 $533
Material adverse event (2)
 31
 60
 12
 103
Total $499
 $68
 $69
 $636
(1)
Includes $205 million and $47 million that are also considered accelerations of payment or funding obligations for FES and the Utilities, respectively.
(2)
Includes $31 million that is also considered an acceleration of payment or funding obligation at FES.

Certain bilateral non-affiliate contracts including power contracts with affiliates awarded through competitive bidding processes, typicallyentered into by the Competitive Energy Services segment contain margining provisions whichthat require the posting of cash or LOCs in amounts determined by future power price movements.collateral. Based on FES’FES' and AE Supply's power portfolioportfolios exposure as of December 31, 2009,2011, FES and forward prices asAE Supply have posted collateral of that date, FES had $179$88 million outstanding in margining accounts. Under a hypothetical adverse change in forward prices (95% confidence level change in forward prices over a one year time horizon), FES would be required to post an additional $129 million.and$1 million, respectively. Depending on the volume of forward contracts entered and future price movements, higher amounts for margining could be required.

Not included in the preceding information is potential collateral arising from the PSAs between FES couldor AE Supply and affiliated utilities in the Regulated Distribution Segment. As of December 31, 2011, neither FES nor AE Supply had any collateral posted with their affiliates. In the event of a senior unsecured credit rating downgrade to below S&P's BB- or Moody's Ba3, FES and AE Supply would be required to post significantly higher amounts for margining.$49 millionand$24 million, respectively.

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 an amount up to $500 million. The Surplus Margin Guaranty is secured by an NGC FMB issued in favor of the Ohio Companies.

FES’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 willwould have claims against each of FES, FGCO and NGC, regardless of whether their primary obligor is FES, FGCO or NGC.
Signal Peak and Global Rail are borrowers under a $350 million syndicated two-year senior secured term loan facility due in October 2012. FirstEnergy, together with WMB Loan Ventures, LLC and WMB Loan Ventures II, LLC, the entities that previously shared ownership in the borrowers with FEV, have provided a guaranty of the borrowers' obligations under the facility. On October 18, 2011, FEV sold a portion of its ownership interest in Signal Peak and Global Rail (see Note 8, Variable Interest Entities). Following the sale, FirstEnergy, WMB Loan Ventures, LLC and WMB Loan Ventures II, LLC, together with Global Mining Group, LLC and Global Holding will continue to guarantee the borrowers' obligations until either the facility is replaced with non-recourse financing (no later than June 30, 2012) or replaced with appropriate recourse financing no earlier than September 4, 2012, that provides for separate guarantees from each owner in proportion with each equity owner's percentage ownership in the joint venture. In addition, FEV, Global Mining Group, LLC and Global Holding, the entities that own direct and indirect equity interests in the borrowers, have pledged those interests to the lenders under the current facility as collateral.
OFF-BALANCE SHEET ARRANGEMENTS

FES and the Ohio Companies have obligations that are not included on ourtheir 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, was $1.7$1.6 billion as of December 31, 2009,2011. See Note 6, Leases of the Combined Notes to the Consolidated Financial Statements for further information on FirstEnergy's and December 31, 2008.

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

MARKET RISK INFORMATION

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

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Commodity Price Risk

FirstEnergy is exposed to financial and market risks resulting from the fluctuation offluctuating interest rates and commodity prices, associated withincluding prices for electricity, energy transmission, natural gas, coal nuclear fuel and emission allowances. To manageenergy transmission. FirstEnergy's Risk Management Committee is responsible for promoting the volatility relating to these exposures,effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. FirstEnergy uses a variety of non-derivative and derivative instruments for risk management purposes 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 and certain purchase power contracts (see Note 6). The NUG entities 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 2009 is summarized in the following table:

Increase (Decrease) in the Fair Value of Derivative Contracts Non-Hedge  Hedge  Total 
  (In millions) 
Change in the Fair Value of Commodity Derivative Contracts:         
Outstanding net liability as of January 1, 2009
 $(304) $(41) $(345)
Additions/change in value of existing contracts
  (673)  (1)  (674)
Settled contracts
  347   27   374 
Outstanding net liability as of December 31, 2009(1)
 $(630) $(15) $(645)
             
Net Liabilities-Derivative Contracts as of December 31, 2009
 $(630) $(15) $(645)
             
Impact of Changes in Commodity Derivative Contracts(2)
            
Income Statement effects (pre-tax)
 $(204) $-  $(204)
Balance Sheet effects:
            
OCI (pre-tax)
 $-  $26  $26 
Regulatory asset (net)
 $122  $-  $122 

(1)Includes $425 million of non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory asset.
(2)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 December 31, 2009 as follows:

Balance Sheet Classification Non-Hedge  Hedge  Total 
  (In millions) 
Current-         
Other assets
 $-  $3  $3 
Other liabilities
  (108)  (17)  (125)
             
Non-Current-
            
Other deferred charges
  218   11   229 
Other noncurrent liabilities
  (740)  (12)  (752)
Net liabilities
 $(630) $(15) $(645)

The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, FirstEnergy relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FirstEnergy uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making (see Note 5)9, Fair Value Measurements of the Combined Notes to the Consolidated Financial Statements). Sources of information for the valuation of commodity derivative contracts assets and liabilities as of December 31, 20092011 are summarized by year in the following table:


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85
Source of Information-
Fair Value by Contract Year
 2012 2013 2014 2015 2016 Thereafter Total
  (In millions)
Prices actively quoted(1)
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Other external sources(2)
 (211) (51) (32) (22) —
 —
 (316)
Prices based on models (21) —
 —
 —
 8
 31
 18
Total(3)
 $(232) $(51) $(32) $(22) $8
 $31
 $(298)
Source of Information               
- Fair Value by Contract Year
 
2010
 
2011
 
2012
 
2013
 
2014
 
Thereafter
 
Total
 
  (In millions) 
Prices actively quoted(1)
  $(11) $-  $-  $-  $-  $-  $(11)
Other external sources(2)
   (369)  (305)  (139)  (44)  -   -   (857)
Prices based on models   -   -   -   -   11   212   223 
Total(3)
  $(380) $(305) $(139) $(44) $11  $212  $(645)

(1)
Represents exchange traded New York Mercantile Exchange traded.futures and options.
(2)
Broker quote sheets.Primarily represents contracts based on broker and IntercontinentalExchange quotes.
(3)
Includes $425$(301) million in non-hedge commodity derivative contracts (primarily with NUGs), whichthat are offset by aprimarily related to NUG contracts. NUG contracts are subject to regulatory asset.accounting and do not materially impact earnings.

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 December 31, 2009. Based on derivative contracts held as of December 31, 2009,2011, an adverse 10% change in commodity prices would decrease net income by approximately $9$13 million after tax during the next 12 months.

Interest Rate Risk

OurFirstEnergy’s exposure to fluctuations in market interest rates is reduced since a significant portion of our debt has fixed interest rates, as noted in the table below.

Comparison of Carrying Value to Fair Value 
                 There-     Fair 
Year of Maturity 2010  2011  2012  2013  2014  after  Total  Value 
  (Dollars in millions) 
Assets
                        
Investments Other Than Cash
                        
and Cash Equivalents:
                        
Fixed Income
 $84  $79  $95  $118  $110  $1,834  $2,320  $2,413 
Average interest rate
  7.1%  7.8%  7.8%  7.6%  8.0%  4.3%  5.0%    
                                 
Liabilities
                                
Long-term Debt:
                                
Fixed rate
 $202  $336  $97  $555  $529  $9,915  $11,634  $12,350 
Average interest rate
  5.7%  6.7%  7.7%  5.9%  5.4%  6.5%  6.5%    
Variable rate
 $62                  $2,057  $2,119  $2,152 
Average interest rate
  3.3%                  1.8%  1.8%    
Short-term Borrowings:
 $1,181                      $1,181  $1,181 
Average interest rate
  0.7%                      0.7%    

We are FirstEnergy is subject to the inherent interest rate risks related to refinancing maturing debt by issuing new debt securities. As discussed in Note 76, Leases of the Combined Notes to the consolidated financial statements, ourConsolidated Financial Statements, FirstEnergy’s investments in capital trusts effectively reduce future lease obligations, also reducing interest rate risk.

Interest Rate Swap Agreements – 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. Swap maturities, call options, fixed interest rates and interest payment dates match those of the underlying obligations. As of December 31, 2009, the debt underlying the $250 million outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 6.45%, which the swaps have converted to a current weighted average variable rate of 5.4%. The fair value of the interest rate swaps designated as fair value hedges was immaterial as of December 31, 2009.

Forward Starting Swap Agreements - Cash Flow Hedges

FirstEnergy uses forward starting swap agreements to hedge a portion of the consolidated interest rate risk associated with issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. During 2009, FirstEnergy terminated forward swaps with a notional value of $2.8 billion and recognized losses of approximately $18.5 million, 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.

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  December 31, 2009 December 31, 2008 
  Notional Maturity Fair Notional Maturity Fair 
Forward Starting Swaps Amount Date Value Amount Date Value 
  (In millions) 
Cash flow hedges  $-   2009   -   100   2009  $(2)
    100   2010   -   100   2010   (2)
    -   2019   -   100   2019   1 
   $100      $-  $300      $(3)
Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income $89
 $100
 $110
 $76
 $23
 $2,008
 $2,406
 $2,456
Average interest rate 8.8% 8.9% 9.0% 9.5% 10.3% 5.4% 6.0%  
Liabilities:                
Long-term Debt:                
Fixed rate $751
 $964
 $866
 $1,330
 $891
 $11,628
 $16,430
 $18,585
Average interest rate 7.3% 5.9% 5.4% 4.7% 5.9% 6.2% 6.1%  
Variable rate 
 $150
 
 
 
 $585
 $735
 $735
Average interest rate   1.8%       0.1% 0.4%  
Equity Price Risk

FirstEnergy provides a noncontributory qualified defined benefit pension planplans that coverscover substantially all of its employees and non-qualified pension plans that cover certain employees. The plan providesplans provide defined benefits based on years of service and compensation levels.
FirstEnergy also provides healtha portion of non-contributory pre-retirement basic life insurance for employees who are eligible to retire. Health care benefits, (whichwhich include certain employee contributions, deductibles and co-payments)co-payments, are also available upon retirement to certain employees, hired prior to January 1, 2005, their dependents and, under certain circumstances, their survivors. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.
The benefit plan assets and obligations are remeasured annually using a December 31 measurement date or as significant triggering events occur. In 2009, FirstEnergy remeasured its other postretirement benefit plans on May 31, 2009, and its qualified defined pension plan on August 31, 2009, as discussed below.

FirstEnergy’s other postretirement benefits plans were remeasured as of May 31, 2009 as a result of a plan amendment announced on June 2, 2009, which reduced future health care coverage subsidies paid by FirstEnergy on behalf of plan participants. The remeasurement and plan amendment resulted in a $48 million reduction in FirstEnergy’s net postretirement benefit cost (including amounts capitalized) for 2009 (see Note 3). This reduction was partially offset by an additional $13 million of net postretirement benefit cost (including amounts capitalized) related to an additional liability created by the VERO offered by FirstEnergy to qualified employees (see Note 3).

On September 2, 2009, FirstEnergy elected to remeasured 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) and reduced FirstEnergy’s net postretirement benefit cost (including amounts capitalized) for 2009 by $7 million (see Note 3). Increases in plan assets from investment gains during 2009 resulted in an increase to the plans' funded status of $349 million on and an after-tax decrease to common stockholders' equity of $19 million. The overall actual investment result during 2009 was a gain of 13.6% compared to an assumed 9% positive return. Based on a 6% discount rate, 2010 pre-tax net periodic pension and OPEB expense will be approximately $89 million. As of December 31, 2009,2011, the FirstEnergy pension plan was underfunded.invested in approximately 19% of equity securities, 48% of fixed income securities, 21% of absolute return strategies, 6% of real estate, 2% of private equity and 4% of cash. A decline in the value of pension plan assets could result in additional funding requirements. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. During 2011, FirstEnergy currently estimates thatmade pre-tax contributions to its qualified pension plans of $372 million. FirstEnergy made an additional cash contributions will be required beginning in$600 million pre-tax contribution to the qualified pension plan on January 5, 2012.

Nuclear decommissioning trustNDT funds have been established to satisfy NGC’s and ourcertain of the Utilities’ nuclear decommissioning obligations. As of December 31, 2009,2011, approximately 16%79% of the funds were invested in equityfixed income securities, and 84%12% of the funds were invested in fixed income equity


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securities and 9% were invested in short-term investments, with limitations related to concentration and investment grade ratings. The equity securitiesinvestments are carried at their market valuevalues of approximately $295$1,699 million, $258 million and $207 million for fixed income securities, equity securities and short-term investments, respectively, as of December 31, 2009.2011, excluding ($52) million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $29$26 million reduction in fair value as of December 31, 2009.2011. The decommissioning trusts of JCP&L, Met-Ed and the Pennsylvania CompaniesPenelec 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 recognizerecognized in earnings the unrealized losses on available-for-sale securities held in their NDT as OTTI. A decline in the value of FirstEnergy’s NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During 2011, approximately $1 million, $4 million and $1 million was contributed to the NDTs of JCP&L, OE and TE, respectively. FENOC has submitted a $95 million parental guarantee to the NRC for a short-fall in nuclear decommissioning trusts as other-than-temporary impairments. On June 18, 2009, the NRC informed FENOC that its review tentatively concluded that a shortfall existed in the decommissioning trust fund for Beaver Valley Unit 1. On November 24, 2009, FENOC submitted a revised decommissioning funding calculation using the NRC formula method based on the renewed license forto Beaver Valley Unit 1 which extended operations until 2036. FENOC’s submittal demonstrated that there was a de minimis shortfall. On December 11, 2009, the NRC’s review of FirstEnergy’s methodology for the funding of decommissioning of this facility concluded that there was reasonable assurance of adequate decommissioning funding at the time permanent termination of operations is expected. FirstEnergy continues to evaluate the status of its funding obligations for the decommissioning of these nuclear facilities.and Perry.

CREDIT RISKFERC Matters

CreditPJM Transmission Rate

In April 2007, FERC issued 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, FERC directed that costs for new transmission facilities that are rated at500kV or higher are


9


to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate based on the amount of load served in a transmission zone. Costs for new transmission facilities that are rated at less than500kV, however, are to be allocated on a load flow methodology, which is generally referred to as a “beneficiary pays” approach to allocating the cost of high voltage transmission facilities.

FERC's Opinion 494 order was appealed to the U.S. Court of Appeals for the Seventh Circuit, which issued a decision in August 2009. The court affirmed FERC's ratemaking treatment for existing transmission facilities, but found that FERC had not supported its decision to allocate costs for new500kV and higher voltage facilities on a load ratio share basis and, based on this finding, remanded the rate design issue to FERC.

In an order dated January 21, 2010, FERC set the matter for a “paper hearing” and requested parties to submit written comments pursuant to the schedule described in the order. FERC identifiednineseparate issues for comments and directed PJM to file the first round of comments on February 22, 2010, with other parties submitting responsive comments and then reply comments on later dates. PJM filed certain studies with FERC on April 13, 2010, in response to the FERC order. PJM's filing demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain load serving entities in PJM bearing the majority of the 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. Other utilities and state commissions supported continued socialization of these costs on a load ratio share basis. This matter is awaiting action by FERC. FirstEnergy cannot predict the outcome of this matter or estimate the possible loss or range of loss.

RTO Realignment

On June 1, 2011, ATSI and the ATSI zone entered into PJM. The move was performed as planned with no known operational or reliability issues for ATSI or for the wholesale transmission customers in the ATSI zone.

On February 1, 2011, ATSI in conjunction with PJM filed its proposal with FERC for moving its transmission rate into PJM's tariffs. On April 1, 2011, the MISO TOs (including ATSI) filed proposed tariff language that describes the mechanics of collecting and administering MTEP costs from ATSI-zone ratepayers. From March 20, 2011 through April 1, 2011, FirstEnergy, PJM and the MISO submitted numerous filings for the purpose of effecting movement of the ATSI zone to PJM on June 1, 2011. These filings include amendments to the MISO's tariffs (to remove the ATSI zone), submission of load and generation interconnection agreements to reflect the move into PJM, and submission of changes to PJM's tariffs to support the move into PJM.

On May 31, 2011, FERC issued orders that address the proposed ATSI transmission rate, and certain parts of the MISO tariffs that reflect the mechanics of transmission cost allocation and collection. In its May 31, 2011 orders, FERC approved ATSI's proposal to move the ATSI formula rate into the PJM tariff without significant change. Speaking to ATSI's proposed treatment of the MISO's exit fees and charges for transmission costs that were allocated to the ATSI zone, FERC required ATSI to present a cost-benefit study that demonstrates that the benefits of the move for transmission customers exceed the costs of any such move, which FERC had not previously required. Accordingly, FERC ruled that these costs must be removed from ATSI's proposed transmission rates until such time as ATSI files and FERC approves the cost-benefit study. On June 30, 2011, ATSI submitted the compliance filing that removed the MISO exit fees and transmission cost allocation charges from ATSI's proposed transmission rates. Also on June 30, 2011, ATSI requested rehearing of FERC's decision to require a cost-benefit analysis as part of FERC's evaluation of ATSI's proposed transmission rates. Finally, and also on June 30, 2011, the MISO and the MISO TOs filed a competing compliance filing - one that would require ATSI to pay certain charges related to construction and operation of transmission projects within the MISO even though FERC ruled that ATSI cannot pass these costs on to ATSI's customers. ATSI on the one hand, and the MISO and MISO TOs on the other, have submitted subsequent filings - each of which is intended to refute the other's claims. ATSI's compliance filing and request for rehearing, as well as the pleadings that reflect the dispute between ATSI and the MISO/MISO TOs, are currently pending before FERC.

From late April 2011 through June 2011, FERC issued other orders that address ATSI's move into PJM. Also, ATSI and the MISO were able to negotiate an agreement of ATSI's responsibility for certain charges associated with long term firm transmission rights that, according to the MISO, were payable by the ATSI zone upon its departure from the MISO. ATSI did not and does not agree that these costs should be charged to ATSI but, in order to settle the case and all claims associated with the case, ATSI agreed to a one-time payment of$1.8 millionto the MISO. This settlement agreement has been submitted for FERC's review and approval. The final outcome of those proceedings that address the remaining open issues related to ATSI's move into PJM and their impact, if any, on FirstEnergy cannot be predicted at this time.

MISO Multi-Value Project Rule Proposal

In July 2010, MISO and certain MISO transmission owners jointly filed with FERC their proposed cost allocation methodology for certain new transmission projects. The new transmission projects--described as MVPs - are a class of transmission projects that are approved via the MTEP. The filing parties proposed to allocate the costs of MVPs by means of a usage-based charge that will be applied to all loads within the MISO footprint, and to energy transactions that call for power to be “wheeled through” the MISO as well as to energy transactions that “source” in the MISO but “sink” outside of MISO. The filing parties expect that the MVP proposal will fund the costs of large transmission projects designed to bring wind generation from the upper Midwest to load centers


10


in the east. The filing parties requested an effective date for the proposal of July 16, 2011. On August 19, 2010, MISO's Board approved the first MVP project -- the “Michigan Thumb Project.” Under MISO's proposal, the costs of MVP projects approved by MISO's Board prior to the June 1, 2011 effective date of FirstEnergy's integration into PJM would continue to be allocated to FirstEnergy. MISO estimated that approximately$15 millionin annual revenue requirements would be allocated to the ATSI zone associated with the Michigan Thumb Project upon its completion.

In September 2010, FirstEnergy filed a protest to the MVP proposal arguing that MISO's proposal to allocate costs of MVPs projects across the entire MISO footprint does not align with the established rule that cost allocation is to be based on cost causation (the “beneficiary pays” approach). FirstEnergy also argued that, in light of progress that had been made to date in the ATSI integration into PJM, it would be unjust and unreasonable to allocate any MVP costs to the ATSI zone, or to ATSI. Numerous other parties filed pleadings on MISO's MVP proposal.

In December 2010, FERC issued an order approving the MVP proposal without significant change. Despite being presented with the issue by FirstEnergy and the MISO, the FERC did not address clearly the question of whether the MVP costs would be payable by ATSI or load in the ATSI zone. FERC stated that the MISO's tariffs obligate ATSI to pay all charges that attached prior to ATSI's exit but ruled that the question of the amount of costs that are to be allocated to ATSI or to load in the ATSI zone were beyond the scope of FERC's order and would be addressed in future proceedings.

On January 18, 2011, FirstEnergy requested rehearing of FERC's order. In its rehearing request, FirstEnergy argued that because the MVP rate is usage-based, costs could not be applied to ATSI, which is a stand-alone transmission company that does not use the transmission system. FirstEnergy also renewed its arguments regarding cost causation and the impropriety of allocating costs to the ATSI zone or to ATSI.On October 21, 2011, FERC issued its order on rehearing, but that order did not address FirstEnergy's argument directly. FERC ruled instead that if ATSI was subject to MVP charges then ATSI owed these charges upon exit of the MISO. On October 31, 2011, FESC filed a Petition of Review for the FERC's December 2010 order and October 21, 2011 order on rehearing of that order with the U.S. Court of Appeals for the D.C. Circuit. Other parties also filed appeals of those orders and, in November, 2011, the cases were consolidated for briefing and disposition in the U.S. Court of Appeals for the Seventh Circuit. On January 27, 2012, the court ordered the FERC to file a proposed briefing format and schedule on or before March 20, 2012.

On August 3, 2011, FirstEnergy filed a complaint with FERC based on the FERC's December 2010 order. In the complaint, FirstEnergy argued that ATSI perfected the legal and financial requirements necessary to exit MISO before any MVP responsibilities could attach and asked FERC to rule that MISO cannot charge ATSI for MVP costs. On September 2, 2011, MISO, its TOs and other parties, filed responsive pleadings. On September 19, 2011, ATSI filed an answer. On December 29, 2011, the MISO and the MISO TOs filed a new “Schedule 39” to the MISO's tariff. Schedule 39 purports to establish a process whereby the MISO would bill TOs for MVP costs that, according to the MISO, attached to the utility prior to such TOs withdrawal from the MISO. On January 19, 2012, FirstEnergy filed a protest to the MISO's new Schedule 39 tariff.

On February 27, 2012, FERC issued an order (February 2012 Order) dismissing ATSI's August 3, 2011 complaint. In the February 2012 Order, FERC accepted the MISO's Schedule 39 tariff, subject to hearings and potential refund of MVP charges to ATSI. The basis for any subsequent hearing is whether the Schedule 39 tariff was in effect at the time that ATSI exited the MISO. FirstEnergy is evaluating the February 2012 Order and will determine the next steps.

FirstEnergy cannot predict the outcome of these proceedings or estimate the possible loss or range of loss.

FirstEnergy Companies' PJM FTR Contract Underfunding Complaint

On December 28, 2011, FES and AE Supply filed a complaint with FERC against PJM challenging the ongoing underfunding of FTR contracts, which exist to hedge against transmission congestion in the day-ahead markets. The underfunding is a result of PJM's practice of using the funds that are intended to pay the holders of FTR contracts to pay instead for congestion costs that occur in the real time markets. Underfunding of the FTR contracts resulted in losses of approximately$35 millionto FES and AE Supply in the 2010-2011 Delivery Year. To date, losses for the 2011-2012 Delivery Year are estimated to be approximately$6 million.

On January 13, 2012, PJM filed comments that describe changes to the PJM tariff that, if adopted, should remedy the underfunding issue. Many parties also filed comments supporting FES' and AE Supply's position. Other parties, generally representatives of end-use customers who will have to pay the charges, filed in opposition to the complaint. The matter is currently pending before FERC. FirstEnergy cannot predict the outcome of this matter or estimate the possible loss or range of loss.
California Claims Matters

In October 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the CDWR during 2001. The settlement proposal claims that CDWR is owed approximately$190 millionfor these alleged overcharges. This proposal was made in the context of mediation efforts by FERC and the United States Court of Appeals for the Ninth Circuit in pending proceedings to resolve all outstanding refund and other claims, including claims of alleged price manipulation in the California energy markets during 2000 and 2001. The Ninth Circuit has since remandedoneof those proceedings to FERC, which arises out of claims previously filed with FERC by the California Attorney General on behalf of certain California parties against various sellers


11


in the California wholesale power market, including AE Supply (the Lockyer case). AE Supply and several other sellers filed motions to dismiss the Lockyer case. In March 2010, the judge assigned to the case entered an opinion that granted the motions to dismiss filed by AE Supply and other sellers and dismissed the claims of the California Parties. On May 4, 2011, FERC affirmed the judge's ruling. On June 3, 2011, the California parties requested rehearing of the May 4, 2011 order. The request for rehearing remains pending.

In June 2009, the California Attorney General, on behalf of certain California parties, filed a second complaint with FERC against various sellers, including AE Supply (the Brown case), again seeking refunds for trades in the California energy markets during 2000 and 2001. The above-noted trades with CDWR are the basis for including AE Supply in this new complaint. AE Supply filed a motion to dismiss the Brown complaint that was granted by FERC on May 24, 2011. On June 23, 2011, the California Attorney General requested rehearing of the May 24, 2011 order. That request for rehearing also remains pending. FirstEnergy cannot predict the outcome of either of the above matters or estimate the possible loss or range of loss.

PATH Transmission Project

The PATH Project is comprised of a765kV transmission line that was proposed to extend from West Virginia through Virginia and into Maryland, modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland.

PJM initially authorized construction of the PATH Project in June 2007. In December 2010, PJM advised that its 2011 Load Forecast Report included load projections that are different from previous forecasts and that may have an impact on the proposed in-service date for the PATH Project. As part of its 2011 RTEP, and in response to a January 19, 2011, directive by a Virginia Hearing Examiner, PJM conducted a series of analyses using the most current economic forecasts and demand response commitments, as well as potential new generation resources. Preliminary analysis revealed the expected reliability violations that necessitated the PATH Project had moved several years into the future. Based on those results, PJM announced on February 28, 2011, that its Board of Managers had decided to hold the PATH Project in abeyance in its 2011 RTEP and directed FirstEnergy and AEP, as the sponsoring transmission owners, to suspend current development efforts on the project, subject to those activities necessary to maintain the project in its current state, while PJM conducts more rigorous analysis of the need for the project as part of its continuing RTEP process. PJM stated that its action did not constitute a directive to FirstEnergy and AEP to cancel or abandon the PATH Project. PJM further stated that it will complete a more rigorous analysis of the PATH Project and other transmission requirements and its Board will review this comprehensive analysis as part of its consideration of the 2011 RTEP. On February 28, 2011, affiliates of FirstEnergy and AEP filed motions or notices to withdraw applications for authorization to construct the project that were pending before state commissions in West Virginia, Virginia and Maryland. Withdrawal was deemed effective upon filing the notice with the MDPSC. The WVPSC and VSCC have granted the motions to withdraw.

PATH submitted a filing to FERC to implement a formula rate tariff effective March 1, 2008. In a November 19, 2010 order addressing various matters relating to the formula rate, FERC set the project's base ROE for hearing and reaffirmed its prior authorization of a return on CWIP, recovery of start-up costs and recovery of abandonment costs. In the order, FERC also granted a1.5%ROE incentive adder and a0.5%ROE adder for RTO participation. These adders will be applied to the base ROE determined as a result of the hearing. The PATH Companies, Joint Intervenors, Joint Consumer Advocates and FERC staff have agreed to a four year moratorium. A settlement was reached, which reflects a base ROE of10.4%(plus authorized adders) effective January 1, 2011. Accordingly, the revised ROE was reflected in a revised Projected Transmission Revenue Requirement for 2011 with true-up occurring in 2013. The FirstEnergy portion of the refund for March 1, 2008, through December 31, 2010, is approximately$2 million(inclusive of interest). The refund amount was computed using a base ROE of10.8%plus authorized adders. On October 7, 2011, PATH and six intervenors submitted to FERC an unopposed settlement agreement. Contemporaneous with this submission, PATH and the six intervenors filed with the Chief ALJ of FERC a joint motion for interim approval and authorization to implement the refund on an interim basis pending issuance of a FERC order acting on the settlement agreement. On October 12, 2011, the motion for interim approval and authorization to implement the refund was granted by the Chief ALJ. On February 16, 2012, FERC approved the settlement agreement and dismissed as moot, in light of its approval of the settlement, PATH's pending request for rehearing of the November 19, 2010 order.
Capital Requirements
Our capital spending for 2012 is expected to be approximately$2.1 billion(excluding nuclear fuel).For 2013, we anticipate baseline capital expenditures of approximately $2.0 billion, which exclude any potential additional strategic opportunities, future mandated spending, energy efficiency or environmental spending relating to MATS. Planned capital initiatives are intended to promote reliability, improve operations, and support current environmental and energy efficiency directives.Our capital investments for additional nuclear fuel are expected to be $280 million and $219 million in 2012 and 2013, respectively.
Anticipated capital expenditures for 2012, excluding nuclear fuel, are shown in the following table. Such costs include expenditures for the betterment of existing facilities and for the construction of transmission lines, distribution lines and substations, and other assets.


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2011
Actual
 
Capital
Expenditures
Forecast 2012
 (In millions)
OE$178
 $167
Penn30
 21
CEI120
 110
TE47
 39
JCP&L327
 206
Met-Ed138
 105
Penelec159
 136
MP164
 142
PE96
 89
WP153
 128
ATSI113
 84
TrAIL82
 20
FGCO198
 131
NGC409
 452
AE Supply141
 144
Other subsidiaries128
 116
Total$2,483
 $2,090
During the 2012-2016 period, maturities of, and sinking fund requirements for long-term debt are:
 2012 2013-2016 Total
 (In millions)
FE$—
 $150
 $150
FES270
 1,758
 2,028
OE—
 400
 400
Penn1
 4
 5
CEI22
 381
 403
JCP&L34
 458
 492
Met-Ed—
 429
 429
Penelec—
 195
 195
Other(1)
637
 1,631
 2,268
Total$964
 $5,406
 $6,370
(1)
Includes debt of AE and its subsidiaries and the elimination of certain intercompany debt.
The following tables display consolidated operating lease commitments as of December 31, 2011.
  FirstEnergy  
Operating Leases Lease Payments 
Capital Trust(1)
 Net
  (In millions)
2012 $383
 $125
 $258
2013 382
 130
 252
2014 371
 131
 240
2015 373
 90
 283
2016 344
 29
 315
Years thereafter 1,803
 4
 1,799
Total minimum lease payments $3,656
 $509
 $3,147
(1)
PNBV and Shippingport purchased a portion of the lease obligation bonds associated with certain sale and leaseback transactions. These arrangements effectively reduce lease costs related to those transactions.



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Operating Leases FES 
OE(1)
 CEI 
TE(1)
 JCP&L Met-Ed Penelec
  (In millions)
2012 $237
 $147
 $4
 $64
 $7
 $4
 $3
2013 241
 146
 3
 64
 7
 4
 3
2014 236
 145
 3
 64
 6
 3
 2
2015 239
 145
 2
 64
 5
 4
 2
2016 230
 117
 3
 64
 5
 3
 2
Years thereafter 1,662
 49
 4
 14
 48
 37
 12
Total minimum lease payments $2,845
 $749
 $19
 $334
 $78
 $55
 $24
(1)
Includes certain minimum lease payments associated with NGC's lessor equity interests in Perry and Beaver Valley Unit 2 that are eliminated in consolidation (see Note 6, Leases, of the Combined Notes to the Consolidated Financial Statements).
FirstEnergy expects its existing sources of liquidity to remain sufficient to meet its anticipated obligations and those of its subsidiaries. FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. In addition to internal sources to fund liquidity and capital requirements for 2012 and beyond, FirstEnergy expects to rely on external sources of funds. Short-term cash requirements not met by cash provided from operations are generally satisfied through short-term borrowings. Long-term cash needs may be met through issuances of debt and/or equity securities. FirstEnergy expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements along with continued access to long-term capital markets.
FirstEnergy had no significant short-term debt outstanding as of December 31, 2011. Total short-term bank lines of committed credit to FirstEnergy totaled $5.0 billion. FirstEnergy’s available liquidity as of January 31, 2012, was as follows:
Company Type Maturity Commitment Available Liquidity
      (In millions)
FirstEnergy(1)
 Revolving June 2016 $2,000
 $1,395
FES / AE Supply Revolving June 2016 2,500
 2,498
TrAIL Revolving Jan. 2013 450
 450
AGC Revolving Dec. 2013 50
 —
    Subtotal $5,000
 $4,343
    Cash —
 49
    Total $5,000
 $4,392
(1)
FE and the Utilities
FirstEnergy and certain of its subsidiaries participate in two five-year syndicated revolving credit facilities with aggregate commitments of$4.5 billion(Facilities).
An aggregate amount of$2 billionis available to be borrowed under a syndicated revolving credit facility (FirstEnergy Facility), subject to separate borrowing sublimits for each borrower. The borrowers under the FirstEnergy Facility are FE, OE, Penn, CEI, TE, Met-Ed, ATSI, JCP&L, MP, Penelec, PE and WP. An additional$2.5 billionis available to be borrowed by FES and AE Supply under a separate syndicated revolving credit facility (FES/AE Supply Facility), subject to separate borrowing sublimits for each borrower.
Commitments under each of the Facilities will be available until June 17, 2016, unless the lenders agree, at the request of the applicable borrowers, to up to two additional one-year extensions. Generally, borrowings under each of the Facilities are available to each borrower separately and mature on the earlier of364days from the date of borrowing or the commitment termination date, as the same may be extended.
Borrowings under each of the Facilities are subject to the usual and customary provisions for acceleration upon the occurrence of events of default, including a cross-default for other indebtedness in excess of$100 million, as described further in Note 12, Capitalization.
FirstEnergy also has established$500 millionof revolving credit facilities that are available to TrAIL ($450 million) and AGC($50 million) until January 2013 and December 2013, respectively.
FE’s primary source of cash for continuing operations as a holding company is cash from the operations of its subsidiaries. During 2011, FirstEnergy received $1.8 billion of cash dividends from its subsidiaries and paid$881 millionin cash dividends to common shareholders, including $20 million paid in March by AE to its former shareholders.


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As ofDecember 31, 2011, the Ohio Companies and Penn had the aggregate capability to issue approximately$2.7 billionof 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$232 millionand$20 million, respectively. As a result of the indenture provisions, TE cannot incur any additional secured debt. Met-Ed and Penelec had the capability to issue secured debt of approximately$376 millionand$382 million, respectively, under provisions of their senior note indentures as ofDecember 31, 2011. In addition, based upon their respective FMB indentures, net earnings and available bondable property additions as ofDecember 31, 2011, MP, PE and WP had the capability to issue approximately$1.1 billionof additional FMBs in the aggregate. These companies may be further limited by the financial covenants of the Facilities and subject to current regulatory approvals and applicable statutory and/or charter limitations.
Based upon FGCO’s net earnings and available bondable property additions under its FMB indentures as ofDecember 31, 2011, FGCO had the capability to issue$2.1 billionof additional FMBs under the terms of that indenture. Based upon NGC’s net earnings and available bondable property additions under its FMB indenture as ofDecember 31, 2011, NGC had the capability to issue$2.0 billionof additional FMBs under the terms of that indenture.
To the extent that coverage requirements or market conditions restrict the subsidiaries’ abilities to issue desired amounts of FMBs or preferred stock, they may seek other methods of financing. Such financings could include the sale of preferred and/or preference stock or of such other types of securities as might be authorized by applicable regulatory authorities which would not otherwise be sold. These financings could result in annual interest charges and/or dividend requirements in excess of those that would otherwise be incurred.
Nuclear Operating Licenses
In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse operating license for an additional twenty years, until 2037. By an order dated April 26, 2011, a NRC ASLB granted a hearing on the Davis-Besse license renewal application to a group of petitioners. By this order, the ASLB also admitted two contentions challenging whether FENOC's Environmental Report adequately evaluated (1) a combination of renewable energy sources as alternatives to the renewal of Davis-Besse's operating license, and (2) severe accident mitigation alternatives at Davis-Besse. On May 6, 2011, FENOC filed an appeal with the NRC from the order granting a hearing on the Davis-Besse license renewal application.On January 10, 2012, intervenors petitioned the ASLB for a new contention on the cracking of the Davis-Besse shield building discussed below.
The following table summarizes the current operating license expiration dates for FES' nuclear facilities in service.
Station In-Service Date Current License Expiration
Beaver Valley Unit 1 1976 2036
Beaver Valley Unit 2 1987 2047
Perry 1986 2026
Davis-Besse 1977 2017
Nuclear Regulation
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As ofDecember 31, 2011, FirstEnergy had approximately$2 billioninvested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy's NDT fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy's obligation to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the NDT. On March 28, 2011, FENOC submitted its biennial report on nuclear decommissioning funding to the NRC. This submittal identified a total shortfall in nuclear decommissioning funding for Beaver Valley Unit 1 and Perry of approximately$92.5 million. By letter dated December 29, 2011, FENOC informed the NRC staff that it had increased the parental guarantee to$95 million.
In January 2004, subsidiaries of FirstEnergy filed a lawsuit in the U.S. Court of Federal Claims seeking damages in connection with costs incurred at the Beaver Valley, Davis-Besse and Perry nuclear facilities as a result of the DOE's failure to begin accepting spent nuclear fuel on January 31, 1998. DOE was required to begin accepting spent nuclear fuel by the Nuclear Waste Policy Act (42 USC 10101 et seq) and the contracts entered into by the DOE and the owners and operators of these facilities pursuant to the Act.In January 2012, the applicable FirstEnergy affiliates reached a$48 millionsettlement of these claims.
On October 1, 2011, Davis-Besse was safely shut down for a scheduled outage to install a new reactor vessel head and complete other maintenance activities. The new reactor head, which replaced a head installed in 2002, enhances safety and reliability, and features control rod nozzles made of material less susceptible to cracking. On October 10, 2011, following opening of the building


15


for installation of the new reactor head, a sub-surface hairline crack was identified in one of the exterior architectural elements on the shield building. These elements serve as architectural features and do not have structural significance. During investigation of the crack at the shield building opening, concrete samples and electronic testing found similar sub-surface hairline cracks in most of the building's architectural elements. FENOC's investigation also identified other indications. Included among them were sub-surface hairline cracks in the upper portion of the shield building (above elevation 780') and in the vicinity of the main steam line penetrations.A team of industry-recognized structural concrete experts and Davis-Besse engineers has determined these conditions do not affect the facility's structural integrity or safety.
On December 2, 2011, the NRC issued a CAL which concluded that FENOC provided "reasonable assurance that the shield building remains capable of performing its safety functions." The CAL imposed a number of commitments from FENOC including, submitting a root cause evaluation and corrective actions to the NRC by February 28, 2012, and further evaluations of the shield building. On February 27, 2012, FENOC sent the root cause evaluation to the NRC. Finally, the CAL also stated that the NRC was still evaluating whether the current condition of the shield building conforms to the plant's licensing basis. On December 6, 2011, the Davis-Besse plant returned to service.
By letter dated August 25, 2011, the NRC made a final significance determination (white) associated with a violation that occurred during the retraction of a source range monitor from the Perry reactor vessel. The NRC also placed Perry in the degraded cornerstone column (Column 3) of the NRC's Action Matrix governing the oversight of commercial nuclear reactors. As a result, the NRC staff will conduct several supplemental inspections, culminating in an inspection using Inspection Procedure 95002 to determine if the root cause and contributing causes of risk significant performance issues are understood, the extent of condition has been identified, whether safety culture contributed to the performance issues, and if FENOC's corrective actions are sufficient to address the causes and prevent recurrence.
In light of the impacts of the earthquake and tsunami on the reactors in Fukushima, Japan, the NRC conducted inspections of emergency equipment at U.S. reactors. The NRC also established a Near-Term Task Force to review its processes and regulations in light of the incident, and, on July 12, 2011, the Task Force issued its report of recommendations for regulatory changes. On October 18, 2011, the NRC approved the Staff recommendations, and directed the Staff to implement its near-term recommendations without delay. Ultimately, the adoption of the Staff recommendations on near-term actions is likely to result in additional costs to implement plant modifications and upgrades required by the regulatory process over the next several years, which costs are likely to be material.

On February 16, 2012, the NRC issued a request for information to the licensed operators of 11 nuclear power plants, including Beaver Valley Power Station Units 1 and 2, with respect to the modeling of fuel performance as it relates to "thermal conductivity degradation," which is the potential in older fuel for reduced capacity to transfer heat that could potentially change its performance during various accident scenarios, including loss of coolant accidents. The request for information indicated that this phenomenon has not been accounted for adequately in performance models for the fuel developed by the fuel manufacturer. The NRC is requesting that FENOC provide an analysis to demonstrate that the NRC regulations are being met. Absent that demonstration, the request indicates that the NRC may consider imposing restrictions on reactor operating limits until the issue is satisfactorily resolved.
Nuclear Insurance
The Price-Anderson Act limits the public liability which can be assessed with respect to a nuclear power plant to $12.6 billion (assuming 104 units licensed to operate) for a single nuclear incident, which amount is covered by: (i) private insurance amounting to $375 million; and (ii) $12.2 billion provided by an industry retrospective rating plan required by the NRC pursuant thereto. Under such retrospective rating plan, in the event of a nuclear incident at any unit in the United States resulting in losses in excess of private insurance, up to $118 million (but not more than $18 million per unit per year in the event of more than one incident) must be contributed for each nuclear unit licensed to operate in the country by the licensees thereof to cover liabilities arising out of the incident. Based on their present nuclear ownership and leasehold interests, FirstEnergy’s maximum potential assessment under these provisions would be $470 million (OE-$40 million, NGC-$408 million, and TE-$22 million) per incident but not more than $70 million (OE-$6 million, NGC-$61 million, and TE-$3 million) in any one year for each incident.
In addition to the public liability insurance provided pursuant to the Price-Anderson Act, FirstEnergy has also obtained insurance coverage in limited amounts for economic loss and property damage arising out of nuclear incidents. FirstEnergy is a member of NEIL, which provides coverage (NEIL I) for the extra expense of replacement power incurred due to prolonged accidental outages of nuclear units. Under NEIL I, FirstEnergy’s subsidiaries have policies, renewable yearly, corresponding to their respective nuclear interests, which provide an aggregate indemnity of up to approximately $2.0 billion (OE-$168 million, NGC-$1.7 billion, TE-$90 million) for replacement power costs incurred during an outage after an initial 26-week waiting period. Members of NEIL I pay annual premiums and are subject to assessments if losses exceed the accumulated funds available to the insurer. FirstEnergy’s present maximum aggregate assessment for incidents at any covered nuclear facility occurring during a policy year would be approximately $13 million (OE-$1 million, NGC-$12 million, and TE-less than $1 million).
FirstEnergy is insured as to its respective nuclear interests under property damage insurance provided by NEIL to the operating company for each plant. Under these arrangements, up to $2.8 billion of coverage for decontamination costs, decommissioning costs, debris removal and repair and/or replacement of property is provided. FirstEnergy pays annual premiums for this coverage and is liable for retrospective assessments of up to approximately $66 million (OE-$6 million, NGC-$57 million, TE-$2 million, Met


16


Ed, Penelec, and JCP&L-less than $1 million each) during a policy year.
FirstEnergy intends to maintain insurance against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of FirstEnergy’s plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by FirstEnergy’s insurance policies, or to the extent such insurance becomes unavailable in the future, FirstEnergy would remain at risk for such costs.
The NRC requires nuclear power plant licensees to obtain minimum property insurance coverage of $1.1 billion or the amount generally available from private sources, whichever is less. The proceeds of this insurance are required to be used first to ensure that the licensed reactor is in a safe and stable condition and can be maintained in that condition so as to prevent any significant risk to the public health and safety. Within 30 days of stabilization, the licensee is required to prepare and submit to the NRC a cleanup plan for approval. The plan is required to identify all cleanup operations necessary to decontaminate the reactor sufficiently to permit the resumption of operations or to commence decommissioning. Any property insurance proceeds not already expended to place the reactor in a safe and stable condition must be used first to complete those decontamination operations that are ordered by the NRC. FirstEnergy is unable to predict what effect these requirements may have on the availability of insurance proceeds.
Hydro Relicensing
Yards Creek
The Yards Creek Pumped Storage Project is a400MW hydroelectric project located in Warren County, New Jersey. JCP&L owns an undivided50%interest in the project, and operates the project. PSEG Fossil, LLC, a subsidiary of Public Service Enterprise Group, owns the remaining interest in the plant. The project was constructed in the early 1960s, and became operational in 1965. Authorization to operate the project is by a license issued by the FERC. The existing license expires on February 28, 2013.

In February 2011, JCP&L and PSEG filed a joint application with FERC to renew the license for an additional forty years. The companies are pursuing relicensure through FERC's ILP. Under the ILP, FERC will assess the license applications, issue draft and final Environmental Assessments/Environmental Impact Studies (as required by NEPA), and provide opportunities for intervention and protests by affected third parties. FERC may hold hearings during the two-year ILP licensure period. FirstEnergy expects FERC to issue the new license within the remaining portion of the two-year ILP period. To the extent, however, that the license proceedings extend beyond the February 28, 2013 expiration date for the current license, the current license will be extended yearly as necessary to permit FERC to issue the new license.
Seneca

The Seneca Pumped Storage Project is a451MW hydroelectric project located in Warren County, Pennsylvania owned and operated by FGCO. FGCO holds the current FERC license that authorizes ownership and operation of the project. The current FERC license will expire on November 30, 2015. FERC's regulations call for a five-year relicensing process. On November 24, 2010, and acting pursuant to applicable FERC regulations and rules, FGCO initiated the relicensing process by filing its notice of intent to relicense and PAD in the license docket.

On November 30, 2010, the Seneca Nation filed its notice of intent to relicense and PADs necessary for them to submit a competing application. Section 15 of the FPA contemplates that third parties may file a "competing application" to assume ownership and operation of a hydroelectric facility upon (i) relicensure and (ii) payment of net book value of the plant to the original owner/operator. Nonetheless, FGCO believes it is entitled to a statutory “incumbent preference” under Section 15.

The Seneca Nation and certain other intervenors have asked FERC to redefine the “project boundary” of the hydroelectric plant to include the dam and reservoir facilities operated by the U.S. Army Corps of Engineers. On May 16, 2011, FirstEnergy filed a Petition for Declaratory Order with FERC seeking an order to exclude the dam and reservoir facilities from the project. The Seneca Nation, the New York State Department of Environmental Conservation, and the U.S. Department of Interior each submitted responses to FirstEnergy's petition, including motions to dismiss FirstEnergy's petition. The “project boundary” issue is pending before FERC.

On September 12, 2011, FirstEnergy and the Seneca Nation each filed “Revised Study Plan” documents. These documents describe the parties' respective proposals for the scope of the environmental studies that should be performed as part of the relicensing process. On October 11, 2011, FERC Staff issued a letter order that addressed the Revised Study Plans. In the order, FERC Staff approved FirstEnergy's Revised Study Plan, subject to a finding that the Project is located on “aboriginal lands” of the Seneca Nation. Based on this finding, FERC Staff directed FirstEnergy to consult with the Seneca Nation and other parties about the data set, methodology, and modeling of the hydrological impacts of project operations. FirstEnergy is performing the work necessary to develop a study proposal from which to conduct such consultations. The study process will extend through approximately November of 2013.

FirstEnergy cannot predict the outcome of this matter or estimate the possible loss or range of loss.


17


Environmental Matters
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. Compliance with environmental regulations could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that FirstEnergy 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.
CAA Compliance
FirstEnergy is required to meet federally-approved SO2and NOx emissions regulations under the CAA. FirstEnergy complies with SO2and NOx reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, combustion controls and post-combustion controls, generating more electricity from lower or non-emitting plants and/or using emission allowances. Violations can result in the shutdown of the generating unit involved and/or civil or criminal penalties.
In July 2008,threecomplaints were filed against FGCO in the U.S. District Court for the Western District of Pennsylvania seeking damages based on air emissions from the coal-fired Bruce Mansfield Plant.Twoof these 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 oftwenty-oneindividuals and the other being a class action complaint seeking certification as a class action with theeightnamed plaintiffs as the class representatives. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these complaints.
The states of New Jersey and Connecticut filed CAA citizen suits in 2007 alleging NSR violations at the coal-fired Portland Generation Station against GenOn Energy, Inc. (formerly RRI Energy, Inc. and the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999) and Met-Ed. Specifically, these suits allege that “modifications” at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR permitting in violation of the CAA's PSD program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. In September 2009, the Court granted Met-Ed's motion to dismiss New Jersey's and Connecticut's claims for injunctive relief against Met-Ed, but denied Met-Ed's motion to dismiss the claims for civil penalties. The parties dispute the scope of Met-Ed's indemnity obligation to and from Sithe Energy, and Met-Ed is unable to predict the outcome of this matter or estimate the possible loss or range of loss.
In January 2009, the EPA issued a NOV to GenOn Energy, Inc. alleging NSR violations at the coal-fired Portland Generation Station based on “modifications” dating back to 1986. The NOV also alleged NSR violations at the Keystone and Shawville coal-fired plants based on “modifications” dating back to 1984. Met-Ed, JCP&L and Penelec are unable to predict the outcome of this matter or estimate the possible loss or range of loss.
In each of May and September 2010, New Jersey submitted interstate pollution transport petitions seeking to reduce Portland Generating Station air emissions under section 126 of the CAA. Based on the September 2010 petition, the EPA has finalized emissions limits and compliance schedules to reduce SO2air emissions by approximately 81% at the Portland Station by January 6, 2015. New Jersey's May 2010 petition is still under consideration by the EPA.
In June 2008, the EPA issued a Notice and Finding of Violation to Mission alleging that “modifications” at the coal-fired Homer City Plant occurred from 1988 to the present without preconstruction NSR permitting in violation of the CAA's PSD program. In May 2010, the EPA issued a second NOV to Mission, Penelec, NYSEG and others that have had an obligor's failureownership interest in Homer City containing in all material respects allegations identical to those included in the June 2008 NOV. In January 2011, the DOJ filed a complaint against Penelec in the U.S. District Court for the Western District of Pennsylvania seeking injunctive relief against Penelec based on alleged “modifications” at Homer City between 1991 to 1994 without preconstruction NSR permitting in violation of the CAA's PSD and Title V permitting programs. The complaint was also filed against the former co-owner, NYSEG, and various current owners of Homer City, including EME Homer City Generation L.P. and affiliated companies, including Edison International. In addition, the Commonwealth of Pennsylvania and the States of New Jersey and New York intervened and have filed separate complaints regarding Homer City seeking injunctive relief and civil penalties. In January 2011, another complaint was filed against Penelec and the other entities described above in the U.S. District Court for the Western District of Pennsylvania seeking damages based on Homer City's air emissions as well as certification as a class action and to enjoin Homer City from operating except in a “safe, responsible, prudent and proper manner.” In October 2011, the Court dismissed all of the claims with prejudice of the U.S. and the Commonwealth of Pennsylvania and the States of New Jersey and New York and all of the claims of the private parties, without prejudice to re-file state law claims in state court, against all of the defendants, including Penelec.In December 2011, the U.S., the Commonwealth of Pennsylvania and the States of New Jersey and New York all filed notices appealing to the Third Circuit Court of Appeals. Penelec believes the claims are without merit and intends to defend itself against the allegations made in these complaints, but, at this time, is unable to predict the outcome of this matter or estimate the loss or possible range of loss. Mission is seeking indemnification from NYSEG and Penelec, the co-owners of Homer City prior to its sale in 1999. On February 13, 2012, the Sierra Club notified the current owner and operator of Homer City, Homer City OL1-OL8 LLC and EME Homer City Generation L.P., that it intends to file a CAA citizen suit regarding its Title V permit and SO2emissions from the Homer City Plant.
In August 2009, the EPA issued a Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, including the PSD, NNSR and Title V regulations, at the Eastlake, Lakeshore, Bay Shore and Ashtabula coal-fired plants. The EPA's NOV alleges equipment replacements during maintenance outages dating back to 1990 triggered the pre-construction permitting requirements under the PSD and NNSR programs. FGCO also received a request for certain operating and maintenance information and planning


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information for these same generating plants and notification that the EPA is evaluating whether certain maintenance at the Eastlake Plant may constitute a major modification under the NSR provisions of the CAA. Later in 2009, FGCO also received another information request regarding emission projections for the Eastlake Plant. In June 2011, EPA issued another Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, specifically opacity limitations and requirements to continuously operate opacity monitoring systems at the Eastlake, Lakeshore, Bay Shore and Ashtabula coal-fired plants. Also, in June 2011, FirstEnergy received an information request pursuant to section 114(a) of the CAA for certain operating, maintenance and planning information, among other information regarding these plants. 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 or estimate the possible loss or range of loss.
In August 2000, AE received an information request pursuant to section 114(a) of the CAA from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the followingtencoal-fired plants, which collectively include22electric generation units: Albright, Armstrong, Fort Martin, Harrison, Hatfield's Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island to determine compliance with the NSR provisions under the CAA, which can require the installation of additional air emission control equipment when a major modification of an existing facility results in an increase in emissions. AE has provided responsive information to this and a subsequent request but is unable to predict the outcome of this matter or estimate the possible loss or range of loss.
In May 2004, AE, AE Supply, MP and WP received a Notice of Intent to Sue Pursuant to CAA §7604 from the Attorneys General of New York, New Jersey and Connecticut and from the PA DEP, alleging that Allegheny performed major modifications in violation of the PSD provisions of the CAA at the following West Virginia coal-fired generation units: Albright Unit 3; Fort Martin Units 1 and 2; Harrison Units 1, 2 and 3; Pleasants Units 1 and 2 and Willow Island Unit 2. The Notice also alleged PSD violations at the Armstrong, Hatfield's Ferry and Mitchell coal-fired plants in Pennsylvania and identifies PA DEP as the lead agency regarding those facilities. In September 2004, AE, AE Supply, MP and WP received a separate Notice of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.
In June 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed suit against AE, AE Supply, MP, PE and WP in the United States District Court for the Western District of Pennsylvania alleging, among other things, that Allegheny performed major modifications in violation of the CAA and the Pennsylvania Air Pollution Control Act at the coal-fired Hatfield's Ferry, Armstrong and Mitchell Plants in Pennsylvania. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. A non-jury trial on liability only was held in September 2010. Plaintiffs filed their proposed findings of fact and conclusions of law in December 2010, Allegheny made its related filings in February 2011 and plaintiffs filed their responses in April 2011. The parties are awaiting a decision from the District Court, but there is no deadline for that decision and we are unable to predict the outcome or estimate the possible loss or range of loss.
In September 2007, Allegheny received a NOV from the EPA alleging NSR and PSD violations under the CAA, as well as Pennsylvania and West Virginia state laws at the coal-fired Hatfield's Ferry and Armstrong plants in Pennsylvania and the coal-fired Fort Martin and Willow Island plants in West Virginia.
FirstEnergy intends to vigorously defend against the CAA matters described above but cannot predict their outcomes or estimate the possible loss or range of loss.
State Air Quality Compliance
In early 2006, Maryland passed the Healthy Air Act, which imposes state-wide emission caps on SO2and NOx, requires mercury emission reductions and mandates that Maryland join the RGGI and participate in that coalition's regional efforts to reduce CO2emissions. On April 20, 2007, Maryland became the tenth state to join the RGGI. The Healthy Air Act provides a conditional exemption for the R. Paul Smith coal-fired plant for NOx, SO2and mercury, based on a 2006 PJM declaration that the plant is vital to reliability in the Baltimore/Washington DC metropolitan area. Pursuant to the legislation, the MDE passed alternate NOx and SO2limits for R. Paul Smith, which became effective in April 2009. However, R. Paul Smith is still required to meet the Healthy Air Act mercury reductions of80%which began in 2010. The statutory exemption does not extend to R. Paul Smith's CO2emissions. Maryland issued final regulations to implement RGGI requirements in February 2008.FourteenRGGI auctions have been held through the end of calendar year 2011. RGGI allowances are also readily available in the allowance markets, affording another mechanism by which to secure necessary allowances. On March 14, 2011, MDE requested PJM perform an analysis to determine if termination of operation at R. Paul Smith would adversely impact the reliability of electrical service in the PJM region under current system conditions. On June 30, 2011, PJM notified MDE that termination of operation at R. Paul Smith would adversely impact the reliability of electrical service in the PJM region absent transmission system upgrades. On January 26, 2012, FirstEnergy announced that R. Paul Smith is among nine coal-fired plants it intends to retire by September 1, 2012, subject to review of reliability impacts by PJM. FirstEnergy is unable to predict the outcome of this matter or estimate the possible loss or range of loss.
In January 2010, the WVDEP issued a NOV for opacity emissions at the Pleasants coal-fired plant. In August 2011, FirstEnergy and WVDEP resolved the NOV through a Consent Order requiring installation of a reagent injection system to reduce opacity by September 2012.
National Ambient Air Quality Standards
The EPA's CAIR requires reductions of NOx and SO2emissions intwophases (2009/2010 and 2015), ultimately capping SO2


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emissions in affected states to2.5 milliontons annually and NOx emissions to1.3 milliontons annually. In 2008, the U.S. Court of Appeals for the District of Columbia vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” In December 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 opinion. The Court ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOx SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the “8-hour” ozone NAAQS. In July 2011, the EPA finalized the CSAPR, to replace CAIR,requiring reductions of NOx and SO2emissions intwo phases (2012 and 2014), ultimately capping SO2emissions in affected states to2.4 milliontons annually and NOx emissions to1.2 milliontons annually. CSAPR allows trading of NOx and SO2emission allowances between power plants located in the same state and interstate trading of NOx and SO2emission allowances with some restrictions. On February 21, 2012, the EPA revised certain CASPR state budgets (for Florida, Louisiana, Michigan, Mississippi, Nebraska, New Jersey, New York, Texas, and Wisconsin and new unit set-asides in Arkansas and Texas), certain generating unit allocations (for some units in Alabama, Indiana, Kansas, Kentucky, Ohio and Tennessee) for NOx and SO2emissions and delayed from 2012 to 2014 certain allowance penalties that could apply with respect to interstate trading of NOx and SO2emission allowances.On December 30, 2011, CSAPR was stayed by the U.S. Court of Appeals for the District of Columbia Circuit pending a decision on legal challenges raised in appeals filed by various stakeholders and scheduled to be argued before the Court on April 13, 2012. The Court ordered EPA to continue administration of CAIR until the Court resolves the CSAPR appeals. Depending on the outcome of these proceedings and how any final rules are ultimately implemented, FGCO's and AE Supply's future cost of compliance may be substantial and changes to FirstEnergy's operations may result.

During 2011, FirstEnergy recorded pre-tax impairment charges of approximately$6 million($1 millionfor FES and$5 millionfor AE Supply) for NOx emission allowances that were expected to be obsolete after 2011 and approximately$21 million($18 millionfor FES and$3 millionfor AE Supply) for excess SO2emission allowances in inventory that it expects will not be consumed in the future.
Hazardous Air Pollutant Emissions
On December 21, 2011, the EPA finalized the MATS to establish emission standards for mercury, hydrochloric acid and various metals for electric generating units. The MATS establishes emission limits for mercury, PM, and HCL for all existing and new coal-fired electric generating units effective in April 2015 and allows averaging of emissions from multiple units located at a single plant. Under the CAA, state permitting authorities can grant an additional compliance year through April 2016, as needed, including instances when necessary to maintain reliability where electric generating units are being closed. In addition, an EPA enforcement policy document contemplates up to an additional year to achieve compliance, through April 2017, under certain circumstances for reliability critical units. On January 26, 2012 and February 8, 2012, FGCO, MP and AE Supply announced the retirement by September 1, 2012 (subject to a reliability review by PJM) of nine coal-fired power plants (Albright, Armstrong, Ashtabula, Bay Shore except for generating unit 1, Eastlake, Lake Shore, R. Paul Smith, Rivesville and Willow Island) with a total capacity of3,349megawatts (generating, on average, approximately ten percent of the electricity produced by the companies over the past three years) due to MATS and other environmental regulations. In addition, MP will make a filing with the WVPSC to provide them with information regarding the retirement of its plants. Depending on how the MATS are ultimately implemented, FirstEnergy's future cost of compliance with MATS may be substantial and other changes to FirstEnergy's operations may result.
On February 24, 2012, PJM notified FirstEnergy of its preliminary analysis of the reliability impacts that may result from closure of the older competitive coal-fired generating units. PJM's preliminary analysis indicated that there would be significant reliability concerns that will need to be addressed. FirstEnergy intends to continue to actively engage in discussions with PJM regarding this notification, including the possible continued operation of certain plants.
Climate Change
There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. 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, in June 2009. Certain states, primarily the northeastern states participating in the RGGI and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.
In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that required FirstEnergy to measure and report GHG emissions commencing in 2010. In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA's finding concludes that concentrations of several key GHGs increase the threat of climate change and may be regulated as “air pollutants” under the CAA. In April 2010, the EPA finalized new 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 would not be triggered for electric generating plants and other stationary sources until January 2, 2011, at the earliest. In May 2010, the EPA finalized new thresholds for GHG emissions that define when permits under the CAA's NSR program would be required. The EPA established an emissions applicability threshold of75,000tons per year of CO2equivalents effective January 2, 2011, for existing facilities under the CAA's PSD program.
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 man-made GHG, including CO2, emitted by developed countries


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by 2012. A December 2009 U.N. Climate Change Conference in Copenhagen did not reach a consensus on a successor treaty to the Kyoto Protocol, but did take note of the Copenhagen Accord, a non-binding political agreement that recognized the scientific view that the increase in global temperature should be belowtwodegrees Celsius; includes a commitment by developed countries to provide funds, approaching$30 billionover three years with a goal of increasing to$100 billionby 2020; and establishes the “Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. To the extent that 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 targets from 2020, while developing countries, including Brazil, China and India, would agree to take mitigation actions, subject to their domestic measurement, reporting and verification.A December 2011 U.N. Climate Change Conference in Durban, Africa, established a negotiating process to develop a new post-2020 climate change protocol, called the “Durban Platform for Enhanced Action”. This negotiating process contemplates developed countries, as well as developing countries such as China, India, Brazil, and South Africa, to undertake legally binding commitments post-2020. In addition, certain countries agreed to extend the Kyoto Protocol for a second commitment period, commencing in 2013 and expiring in 2018 or 2020.
In 2009, the U.S. Court of Appeals for the Second Circuit and 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. 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. The U.S. Supreme Court granted a writ of certiorari to review the decision of the Second Circuit. On June 20, 2011, the U.S. Supreme Court reversed the Second Circuit but failed to answer the question of the extent to which actions for damages based on GHG emissions may remain viable. The Court remanded to the Second Circuit the issue of whether the CAA preempted state common law nuisance actions.
FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO2emissions per KWH of electricity generated by FirstEnergy is lower than many of its regional competitors due to its diversified generation sources, which include low or non-CO2emitting gas-fired and nuclear generators.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal CWA and its amendments, apply to FirstEnergy's plants. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy's operations.
In 2004, the EPA established new performance standards under Section 316(b) of the CWA for reducing impacts on fish and shellfish from cooling water intake structures at certain existing electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). In 2007, the Court of Appeals for the Second Circuit invalidated portions of the Section 316(b) performance standards and the EPA has taken the position 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. In April 2009, the U.S. Supreme Court reversed one significant aspect of the Second Circuit's opinion and decided that Section 316(b) of the CWA authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. On March 28, 2011, the EPA released a new proposed regulation under Section 316(b) of the CWA generally requiring fish impingement to be reduced to a12%annual average and studies to be conducted at the majority of our existing generating facilities to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic life. On July 19, 2011, the EPA extended the public comment period for the new proposed Section 316(b) regulation by30days but stated its schedule for issuing a final rule remains July 27, 2012. FirstEnergy is studying various control options and their costs and 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. 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.
In April 2011, the U.S. Attorney's Office in Cleveland, Ohio advised FGCO that it is no longer considering prosecution under the CWA 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. On August 5, 2011, EPA issued an information request pursuant to Sections 308 and 311 of the CWA for certain information pertaining to the oil spills and spill prevention measures at FirstEnergy facilities. FirstEnergy responded on October 10, 2011. On February 1, 2012, FirstEnergy executed a tolling agreement with the EPA extending the statute of limitations to July 31, 2012. FGCO does not anticipate any losses resulting from this matter to be material.
In May 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club filed a CWA citizen suit alleging violations of arsenic limits in the NPDES water discharge permit for the fly ash impoundments at the Albright Station seeking unspecified civil penalties and injunctive relief. The MP filed an answer on July 11, 2011, and a motion to stay the proceedings on July 13, 2011. On January 3, 2012, the Court denied MP's motion to dismiss or stay the CWA citizen suit but without prejudice to re-filing in the future. MP is currently seeking relief from the arsenic limits through WVDEP agency review.



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In June 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club served a60-Day Notice of Intent required prior to filing a citizen suit under the CWA for alleged failure to obtain a permit to construct the fly ash impoundments at the Albright Plant.
FirstEnergy intends to vigorously defend against the CWA matters described above but, except as indicated above, cannot predict their outcomes or estimate the possible loss or range of loss.
Monongahela River Water Quality
In late 2008, the PA DEP imposed water quality criteria for certain effluents, including TDS and sulfate concentrations in the Monongahela River, on new and modified sources, including the scrubber project at the coal-fired Hatfield's Ferry Plant. These criteria are reflected in the current PA DEP water discharge permit for that project. AE Supply appealed the PA DEP's permitting decision, which would require it to incur estimated costs in excess of$150 millionin order to install technology to meet TDS and sulfate limits in the permit or negatively affect its ability to operate the scrubbers as designed. The permit has been independently appealed by Environmental Integrity Project and Citizens Coal Council, which seeks to impose more stringent technology-based effluent limitations. Those same parties have intervened in the appeal filed by AE Supply, and both appeals have been consolidated for discovery purposes. An order has been entered that stays the permit limits that AE Supply has challenged while the appeal is pending. A hearing on the parties' appeals was scheduled to begin in September 2011, however the Court stayed all prehearing deadlines on July 15, 2011 to allow the parties additional time to work out a settlement, and has rescheduled a hearing, if necessary, for July 2012. If these settlement discussions are successful, AE Supply anticipates that its obligations will not be material. AE Supply intends to vigorously pursue these issues, but cannot predict the outcome of these appeals or estimate the possible loss or range of loss.
In a parallel rulemaking, the PA DEP recommended, and in August 2010, the Pennsylvania Environmental Quality Board issued, a final rule imposing end-of-pipe TDS effluent limitations. FirstEnergy could incur significant costs for additional control equipment to meet the requirements of this rule, although its provisions do not apply to electric generating units until the end of 2018, and then only if the EPA has not promulgated TDS effluent limitation guidelines applicable to such units.
In December 2010, PA DEP submitted its CWA 303(d) list to the EPA with a recommended sulfate impairment designation for an approximately68mile stretch of the Monongahela River north of the West Virginia border. In May 2011, the EPA agreed with PA DEP's recommended sulfate impairment designation. PA DEP's goal is to submit a final water quality standards regulation, incorporating the sulfate impairment designation for EPA approval by May, 2013. PA DEP will then need to develop a TMDL limit for the river, a process that will take approximatelyfiveyears. Based on the stringency of the TMDL, FirstEnergy may incur significant costs to reduce sulfate discharges into the Monongahela River from the coal-fired Hatfield's Ferry and Mitchell Plants in Pennsylvania and the coal-fired Fort Martin Plant in West Virginia.
In October 2009, the WVDEP issued the water discharge permit for the Fort Martin Plant. Similar to the Hatfield's Ferry water discharge permit, the Fort Martin permit imposes effluent limitations for TDS and sulfate concentrations. The permit also imposes temperature limitations and other effluent limits for heavy metals that are not contained in the Hatfield's Ferry water discharge permit. Concurrent with the issuance of the Fort Martin permit, WVDEP also issued an administrative order that sets deadlines for MP to meet certain of the effluent limits that are effective immediately under the terms of any investment contract, loan agreement or otherwise perform as agreed. Credit risk arises from all activities inthe permit. MP appealed the Fort Martin permit and the administrative order. The appeal included a request to stay certain of the conditions of the permit and order while the appeal is pending, which success dependswas granted pending a final decision on issuer, borrower or counterparty performance, whether reflected on or offappeal and subject to WVDEP moving to dissolve the balance sheet. We engage in transactionsstay. The appeals have been consolidated. MP moved to dismiss certain of the permit conditions for the purchasefailure of the WVDEP to submit those conditions for public review and comment during the permitting process. An agreed-upon order that suspends further action on this appeal, pending WVDEP's release for public review and comment on those conditions, was entered on August 11, 2010. The stay remains in effect during that process. The current terms of the Fort Martin permit would require MP to incur significant costs or negatively affect operations at Fort Martin. Preliminary information indicates an initial capital investment in excess of the capital investment that may be needed at Hatfield's Ferry in order to install technology to meet the TDS and sulfate limits in the Fort Martin permit, which technology may also meet certain of the other effluent limits in the permit. Additional technology may be needed to meet certain other limits in the permit. MP intends to vigorously pursue these issues but cannot predict the outcome of these appeals or estimate the possible loss or range of loss.
Regulation of Waste Disposal
Federal 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. Certain fossil-fuel combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. In February 2009, the EPA requested comments from the states on options for regulating coal combustion residuals, including whether they should be regulated as hazardous or non-hazardous waste.
In December 2009, in an advance notice of public rulemaking, the EPA asserted that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. In May 2010, the EPA proposedtwooptions for additional regulation of coal combustion residuals, including the option of regulation as a special waste under the EPA's hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. FirstEnergy's future cost of compliance with any coal combustion residuals regulations that may be promulgated could


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be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the EPA or the states. Compliance with those regulations could have an adverse impact on FirstEnergy's results of operations and financial condition.
LBR CCB impoundment is expected to run out of disposal capacity for disposal of CCBs from the BMP between 2016 and 2018. BMP is pursuing several CCB disposal options.
Certain of our 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 ofDecember 31, 2011, based on estimates of the total costs of cleanup, the Utility Registrants' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay.Total liabilities of approximately$106 million(JCP&L -$70 million, TE -$1 million, CEI -$1 million, FGCO -$1 millionand FE -$33 million) have been accrued throughDecember 31, 2011. Included in the total are accrued liabilities of approximately$63 millionfor 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. On July 11, 2011, FirstEnergy was found to be a potentially responsible party under CERCLA, indirectly liable for a portion of past and future clean-up costs at certain legacy MGP sites, estimated to total approximately$59 million. FirstEnergy recognized an additional expense of$29 millionduring the second quarter of 2011;$30 millionhad previously been reserved prior to 2011.FirstEnergy determined that it is reasonably possible that it or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the possible losses or range of losses cannot be determined or reasonably estimated at this time.
Fuel Supply
FirstEnergy currently has long-term coal contracts with various terms to acquire approximately 34.5 million tons of coal for the year 2012 which is approximately 90% of its 2012 coal requirements of 38.5 million tons. This coal requirement excludes the impact of our recently announced decision to close nine older coal-fired plants by September 1, 2012, subject to review for reliability impacts by PJM. This contract coal is produced primarily from mines located in Ohio, Pennsylvania, West Virginia, Montana and Wyoming. The contracts expire at various times through December 31, 2030. See “Environmental Matters” for factors pertaining to meeting environmental regulations affecting coal-fired generating units.
FirstEnergy has contracts for all uranium requirements through 2012 and a portion of uranium material requirements through 2024. Conversion services contracts fully cover requirements through 2012 and partially fill requirements through 2024. Enrichment services are contracted for essentially all of the enrichment requirements for nuclear fuel through 2020. A portion of enrichment requirements is also contracted for through 2024. Fabrication services for fuel assemblies are contracted for both Beaver Valley units through 2013 and Davis-Besse through 2025 and through the current operating license period for Perry. In addition to the existing commitments, FirstEnergy intends to make additional arrangements for the supply of uranium and for the subsequent conversion, enrichment, fabrication, and waste disposal services.

On-site spent fuel storage facilities are expected to be adequate for Beaver Valley Unit 1 through 2014. Davis-Besse has adequate storage through 2017. FENOC is taking actions to extend the spent fuel storage capacity for Beaver Valley Units 1 and 2 and Perry. Plant modifications to increase the storage capacity of the existing spent fuel storage pool at Beaver Valley Unit 2 were approved by the NRC on April 29, 2011 and the plant modifications are expected to be complete in 2012. Once this expansion is complete, Beaver Valley Unit 2 will have spent fuel pool storage capacity through 2022. Dry fuel storage is also being pursued at Beaver Valley with completion projected by the end of 2014. Perry dry fuel storage facilities have been completed with the initial dry fuel storage loading campaign targeted for 2012. Both Beaver Valley Unit 2 and Perry maintain sufficient fuel storage capability to continue operations through the targeted completion dates of their respective storage expansion projects. After current on-site storage capacity at the plants is exhausted, additional storage capacity will have to be obtained either through plant modifications, interim off-site disposal, or permanent waste disposal facilities.

The Federal Nuclear Waste Policy Act of 1982 provided for the construction of facilities for the permanent disposal of high-level nuclear wastes, including spent fuel from nuclear power plants operated by electric utilities. NGC has contracts with the DOE for the disposal of spent fuel for Beaver Valley, Davis-Besse and Perry. Yucca Mountain was approved in 2002 as a repository for underground disposal of spent nuclear fuel from nuclear power plants and high level waste from U.S. defense programs. The DOE submitted the license application for Yucca Mountain to the NRC on June 3, 2008. On March 3, 2010, the DOE filed a motion to withdraw its Yucca Mountain license application with prejudice. The ASLB denied the DOE's withdrawal motion on June 29, 2010. On September 9, 2011, the NRC issued an Order (CLI-11-07) stating that it was evenly divided on whether to overturn or uphold the ASLB's decision, and directing the ASLB to complete all necessary and appropriate case management activities by the close of the fiscal year. The current Administration has stated the Yucca Mountain repository will not be completed and a Federal review of potential alternative strategies is being performed. The President's 2011 budget proposal eliminated funding for Yucca Mountain, and the 2011 DOE appropriation did not include any funds for Yucca Mountain. Likewise, the President's 2012 budget proposal does not provide for funding of Yucca Mountain.

In parallel, several parties filed actions in the U.S. Circuit Court of Appeals for the D.C. Circuit challenging the Department's authority to withdraw the license application in light of its obligations under the Nuclear Waste Policy Act. The first case filed was In re: Aiken County, filed on February 19, 2010. Robert L. Ferguson, et al. filed a petition on February 25, 2010; State of South Carolina filed


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on March 26, 2010; and State of Washington filed on April 13, 2010. These cases have since been consolidated. On May 3, 2010, the D.C. Circuit granted a motion by the National Association of Regulatory Utility Commissioners to intervene. Oral arguments were heard by the D.C. Circuit on March 22, 2011. The D.C. Circuit dismissed the petitions for lack of jurisdiction on July 1, 2011, finding a lack of finality and ripeness until the Commission acts on DOE's motion to withdraw or rules on the license application. In response to the NRC's order from September 2011, the states and other interested parties re-commenced their challenge at the D. C. Circuit, in Aiken County et al., No. 11-1271. Briefing in that appeal was recently completed, and oral argument has been set for May 2, 2012. In light of this uncertainty, FirstEnergy intends to make additional arrangements for storage capacity as a contingency for the continuing delays of the DOE acceptance of spent fuel for disposal.

Fuel oil and natural gas are used primarily to fuel peaking units and/or to ignite the burners prior to burning coal when a coal-fired plant is restarted. Fuel oil requirements have historically been low and are forecasted to remain so. Requirements are expected to average approximately 4 million gallons per year over the next five years. Natural gas is currently consumed primarily by peaking units and demand is forecasted at less than 7 million mcf in 2012.
System Demand
The 2011 maximum hourly demand for each of the Utilities was:
OE—6,070 MW on July 21, 2011;
Penn—1,048 MW on July 21, 2011;
CEI—4,648 MW on July 21, 2011;
TE—2,286 MW on July 21, 2011;
JCP&L—6,588 MW on July 22, 2011;
Met-Ed—3,094 MW on July 22, 2011;
Penelec—3,128 MW on July 22, 2011;
MP—1,989 MW on July 21, 2011;
PE—2,969 MW on July 21, 2011; and
WP—4,017 MW on July 21, 2011
Supply Plan
Regulated Commodity Sourcing
Certain of the Utilities have default service obligations to provide power to non-shopping customers who have elected to continue to receive service under regulated retail tariffs. The volume of these sales can vary depending on the level of shopping that occurs. Supply plans vary by state and by service territory. JCP&L’s default service or BGS supply is secured through a statewide competitive procurement process approved by the NJBPU. The Ohio Companies', Pennsylvania Companies' and PE's Maryland default service supplies are provided through a competitive procurement process approved by the PUCO (under the ESP), PPUC (under the DSP) and MDPSC (under the SOS), respectively. If any supplier fails to deliver power to any one of those Utilities’ service areas, the Utility serving that area may need to procure the required power in the market in their role as a POLR. West Virginia electric generation continues to be regulated by the WVPSC.
Unregulated Commodity Sourcing
The Competitive Energy Services segment, through FES and AE Supply, provides energy and energy related services, including the generation and sale of commodities including gas, electricity coal and emission allowances. These transactionsenergy planning and procurement through retail and wholesale competitive supply arrangements. FES supplies the power requirements of its competitive load-serving obligations through a combination of subsidiary-owned generation, non-affiliated contracts and spot market transactions.
FES and AE Supply have retail and wholesale competitive load-serving obligations in Ohio, Pennsylvania, Illinois, Maryland, Michigan and New Jersey, serving both affiliated and non-affiliated companies. FES and AE Supply provide energy products and services to customers under various POLR, shopping, competitive-bid and non-affiliated contractual obligations. Geographically, most of FES’ and AE Supply's obligations are oftenin the PJM market area where all of its respective generation facilities are located.
Regional Reliability
All of FirstEnergy's facilities are located within PJM and operate under the reliability oversight of a regional entity known as RFC. This regional entity operates under the oversight of the NERC in accordance with major energy companies withina Delegation Agreement approved by the industry.FERC. RFC began operations under the NERC on January 1, 2006. On July 20, 2006, the NERC was certified by the FERC as the ERO


24


in the United States pursuant to Section 215 of the FPA and RFC was certified as a regional entity.
Competition
As a result of actions taken by state legislative bodies, major changes in the electric utility business have occurred in portions of the United States, including Ohio, New Jersey, Pennsylvania and Maryland, where most of FirstEnergy utility subsidiaries operate. These changes have altered the way traditional integrated utilities conduct their business. FirstEnergy has aligned its business units to participate in the competitive electricity marketplace (see Management's Discussion and Analysis for more information regarding FirstEnergy's Competitive Energy Services segment).
FirstEnergy's Competitive Energy Services segment participates in deregulated energy markets in Ohio, Pennsylvania, Maryland, Michigan, New Jersey and Illinois, through FES and AE Supply. In these markets, the Competitive Energy Services segment competes: (1) to provide retail generation service directly to end users; (2) to provide wholesale generation service to utilities, municipalities and co-operatives, which, in turn, resell to their end users, and (3) in the wholesale market. The success of the Competitive Energy Services segment is driven by its ability to successfully compete against other retail markets and/or generators and to produce revenues that exceed costs.
Seasonality
The sale of electric power is generally a seasonal business and weather patterns can have a material impact on FirstEnergy’s operating results. Demand for electricity in our service territories historically peaks during the summer and winter months, with market prices also generally peaking at that time. Accordingly, FirstEnergy’s annual results of operations and liquidity position may depend disproportionately on its operating performance during the summer and winter. Mild weather conditions may result in lower power sales and consequently lower earnings.
Research and Development
The Utilities, FES, FGCO and FENOC participate in the funding of EPRI, which was formed for the purpose of expanding electric R&D under the voluntary sponsorship of the nation’s electric utility industry — public, private and cooperative. Its goal is to mutually benefit utilities and their customers by promoting the development of new and improved technologies to help the utility industry meet present and future electric energy needs in environmentally and economically acceptable ways. EPRI conducts research on all aspects of electric power production and use, including fuels, generation, delivery, energy management and conservation, environmental effects and energy analysis. The majority of EPRI’s research and development projects are directed toward practical solutions and their applications to problems currently facing the electric utility industry.
FirstEnergy participates in other initiatives with industry R&D consortiums and universities to address technology needs for its various business units. Participation in these consortiums helps the company address research needs in areas such as plant operations and maintenance, major component reliability, environmental controls, advanced energy technologies, and transmission and distribution system infrastructure to improve performance, and develop new technologies for advanced energy and grid applications.


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87
Executive Officers
Name Age Positions Held During Past Five Years Dates
A. J. Alexander 60  President and Chief Executive Officer (A)(B) *-present
    Chief Executive Officer (F) *-present
    President and Chief Executive Officer (H) 2011-present
    President (C)(D) *-2008
       
L. M. Cavalier 60  Senior Vice President, Human Resources (B) *-present
    Senior Vice President, Human Resources (H) 2011-present
       
M. T. Clark 61  President and Chief Financial Officer (G)(L) 2012-present
    Executive Vice President and Chief Financial Officer (A)(B)(C)(D)(E)(F) 2009-present
    Executive Vice President and Chief Financial Officer (H)(I)(J)(K) 2011-present
    Executive Vice President and Chief Financial Officer (G) 2011
    Executive Vice President, Strategic Planning & Operations (A)(B) 2008-2009
    Senior Vice President, Strategic Planning & Operations (B) *-2008
       
M. J. Dowling 47 Senior Vice President, External Affairs (B)(H) 2011-present
    Vice President, External Affairs (B) 2010-2011
    Vice President, Communications (B) 2008-2010
    Vice President, Governmental Affairs (B) 2007-2008
    Vice President (B) *-2007
       
C. E. Jones 56  Senior Vice President & President, FirstEnergy Utilities (B) 2010-present
    Senior Vice President & President, FirstEnergy Utilities (H) 2011-present
    President (J)(K) 2011-present
    President (C)(D) 2010-present
    Senior Vice President & President, FirstEnergy Utilities (A) 2010-2011
    Senior Vice President, Energy Delivery & Customer Service (B) 2009-2010
    President (E) 2007-2009
    Senior Vice President (B)(C)(D) *-2007
       
J. H. Lash 61  President FE, Generation (B)(H) 2011-present
    Chief Nuclear Officer (F) 2011-present
    President (I) 2011-present
    President and Chief Nuclear Officer (F) 2010-2011
    Senior Vice President and Chief Operating Officer (F) 2007-2010
    Vice President, Beaver Valley (F) *-2007
       
G. R. Leidich 61  Executive Vice President, Integration (A)(B)(H)(M) 2011
    President (G)(M) 2011
    Executive Vice President & President, FirstEnergy Generation (A)(B)(M) 2008-2011
    Senior Vice President, Operations (B) 2007-2008
    President and Chief Nuclear Officer (F) *-2007
       
J. F. Pearson 57  Vice President and Treasurer (A)(B)(C)(D)(E)(F) *-present
    Vice President and Treasurer (G)(H)(I)(J)(K) 2011-present
       
D. R. Schneider 50  President (E) 2009-present
    Senior Vice President, Energy Delivery & Customer Service (B) 2007-2009
    Senior Vice President (C)(D) 2007-2009
    Vice President (B) *-2007
       
L. L. Vespoli 52  Executive Vice President and General Counsel (A)(B)(C)(D)(E)(F) 2008-present
    Executive Vice President and General Counsel (G)(H)(I)(J)(K) 2011-present
    Senior Vice President and General Counsel (A)(B)(C)(D)(E)(F) *-2008
       
H. L. Wagner 59  Vice President, Controller and Chief Accounting Officer (A) *-present
    Vice President and Controller (C)(D)(E)(F) *-present
    Vice President and Controller (G)(I)(J)(K) 2011-present
    Vice President, Controller and Chief Accounting Officer (H) 2011-present
    Vice President, Controller and Chief Accounting Officer (B) 2010-present
    Vice President and Controller (B) *-2010
* Indicates position held at least since January 1, 2007(E) Denotes executive officer of FES(J) Denotes executive officer of MP, PE and WP
(A) Denotes executive officer of FE(F) Denotes executive officer of FENOC(K) Denotes executive officer of TrAIL
(B) Denotes executive officer of FESC(G) Denotes executive officer of AE(L) Position effective January 1, 2012
(C) Denotes executive officer of OE, CEI and TE(H) Denotes executive officer of AESC(M) Retired on December 31, 2011
(D) Denotes executive officer of Met-Ed, Penelec and Penn(I) Denotes executive officer of AGC


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Employees
We maintain credit policies with respect to our counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of our credit program, we aggressively manage the quality of our portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB (S&P). As of December 31, 2009,2011, FirstEnergy’s subsidiaries had 17,257 employees located in the largest credit concentration was with Morgan Stanley, which is currently rated investment grade, representing 7.3% of our total approved credit risk.

REGULATORY MATTERS

Regulatory assets that do not earn a current return totaled approximately $187 millionUnited States as of December 31, 2009 (JCP&L - $36 million, Met-Ed - $114 million, and Penelec - $37 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 regulatory assets by company:
follows:
 December 31,  December 31,  Increase 
Regulatory Assets 2009  2008  (Decrease) 
 (In millions) 
Total
Employees
 
Bargaining
Unit
Employees
FESC2,975
 293
AESC(1)
3,971
 1,177
OE $465  $575  $(110)1,222
 714
CEI  546   784   (238)897
 608
TE  70   109   (39)390
 290
Penn204
 153
JCP&L  888   1,228   (340)1,413
 1,090
Met-Ed  357   413   (56)678
 488
Penelec  9   -(1)  9 896
 638
ATSI  21   31   (10)38
 —
FES273
 —
FGCO1,652
 1,061
FENOC2,648
 957
Total $2,356  $3,140  $(784)17,257
 7,469
(1)
Penelec had net regulatory liabilitiesAESC employs substantially all 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.former Allegheny personnel who provide services to AE and its subsidiaries, including AE Supply, AGC, MP, PE, WP and TrAIL.
FirstEnergy Web Site
Each of the registrant’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are also made available free of charge on or through FirstEnergy’s internet Web site at www.firstenergycorp.com. These reports are posted on the Web site as soon as reasonably practicable after they are electronically filed with the SEC. Additionally, we routinely post important information on our Web site and recognize our Web site as a channel of distribution to reach public investors and as a means of disclosing material non-public information for complying with disclosure obligations under the SEC's Regulation FD. Information contained on FirstEnergy’s Web site shall not be deemed incorporated into, or to be part of, this report.
Regulatory assetsIn accordance with SEC rules, FirstEnergy will include disclosure of any amendment or waiver to its Code of Ethics or a provision of that Code on its Internet Web site within four business days following the date of any such amendment or waiver.
ITEM 1A.RISK FACTORS
We operate in a business environment that involves significant risks, many of which are beyond our control. Management of each Registrant regularly evaluates the most significant risks of the Registrant’s businesses and reviews those risks with the FirstEnergy Board of Directors or appropriate Committees of the Board. The following risk factors and all other information contained in this report should be considered carefully when evaluating FirstEnergy and our subsidiaries. These risk factors could affect our financial results and cause such results to differ materially from those expressed in any forward-looking statements made by sourceor on behalf of us. Below, we have identified risks we currently consider material. Additional information on risk factors is included in “Item 1. Business” and “Item 7. Management’s Discussion and Analysis of Registrant and Subsidiaries” and in other sections of this Form 10-K that include forward-looking and other statements involving risks and uncertainties that could impact our business and financial results.
Risks Related to Business Operations
Risks Arising from the Reliability of Our Power Plants and Transmission and Distribution Equipment
Operation of generation, transmission and distribution facilities involves risk, including the risk of potential breakdown or failure of equipment or processes due to aging infrastructure, fuel supply or transportation disruptions, accidents, labor disputes or work stoppages by employees, acts of terrorism or sabotage, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions resulting from environmental limitations and governmental interventions, and performance below expected levels. In addition, weather-related incidents and other natural disasters can disrupt generation, transmission and distribution delivery systems. Because our transmission facilities are as follows:interconnected with those of third parties, the operation of our facilities could be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties.

  December 31,  December 31,  Increase 
Regulatory Assets By Source 2009  2008  (Decrease) 
  (In millions) 
Regulatory transition costs $1,100  $1,452  $(352)
Customer shopping incentives  154   420   (266)
Customer receivables for future income taxes  329   245   84 
Loss on reacquired debt  51   51   - 
Employee postretirement benefits  23   31   (8)
Nuclear decommissioning, decontamination            
and spent fuel disposal costs  (162)  (57)  (105)
Asset removal costs  (231)  (215)  (16)
MISO/PJM transmission costs  148   389   (241)
Fuel costs  369   214   155 
Distribution costs  482   475   7 
Other  93   135   (42)
Total $2,356  $3,140  $(784)

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On June 7, 2007,Operation of our power plants below expected capacity could result in lost revenues and increased expenses, including higher operating and maintenance costs, purchased power costs and capital requirements. Unplanned outages of generating units and extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of our business. Unplanned outages typically increase our operation and maintenance expenses and may reduce our revenues as a result of selling fewer MWH or may require us to incur significant costs as a result of operating our higher cost units or obtaining replacement power from third parties in the open market to satisfy our forward power sales obligations. Moreover, if we were unable to perform under contractual obligations, penalties or liability for damages could result.
FES, FGCO and the Ohio Companies filed an applicationare exposed to losses under their applicable sale-leaseback arrangements for an increase in electric distribution rates withgenerating facilities upon the PUCOoccurrence of certain contingent events that could render those facilities worthless. Although we believe these types of events are unlikely to occur, FES, FGCO and on August 6, 2007, updated their filing. On January 21, 2009, the PUCO granted the Ohio Companies’ application in partCompanies have a maximum exposure to increase electric distribution rates by $136.6loss under those provisions of approximately $1.4 billion for FES, $606 million (OE - $68.9 million, CEI - $29.2 million and TE - $38.5 million). These increases went into effect for OE and an aggregate of $587 million for TE on January 23, 2009, and for CEI on May 1, 2009. Applications for rehearing of this order were filed by the Ohio Companiesas co-lessees.
We remain obligated to provide safe 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.

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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. The PUCO has not yet issued a substantive Entry on Rehearing.  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 generationreliable service to customers within our franchised service territories. Meeting this commitment requires the Ohio Companies’ retail customers who chose notexpenditure of significant capital resources. Failure to shop with alternative suppliers. On January 9, 2009, the Ohio Companies requested the implementation of a new fuel riderprovide safe and reliable service and failure to recover the costs resulting from the December 31, 2008 CBP. The PUCO ultimately approved the Ohio Companies’ request for a new fuel ridermeet regulatory reliability standards due 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 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 regulatory asset, and that the Ohio Companies would collect a delivery service improvement rider at an overall average rate of $.002 per KWH for the period of April 1, 2009 through December 31, 2011. The Amended ESP also addressed a number of other issues,factors, including, but not limited to, rate designequipment failure and weather, could adversely affect our operating results through reduced revenues and increased capital and operating costs and the imposition of penalties/fines or other adverse regulatory outcomes.
Changes in Commodity Prices Could Adversely Affect Our Profit Margins
We purchase and sell electricity in the competitive wholesale and retail markets. Increases in the costs of fuel for various customer classes,our generation facilities (particularly coal, uranium and resolutionnatural gas) can affect our profit margins. Changes in the market price of electricity, which are affected by changes in other commodity costs and other factors, may impact our results of operations and financial position by increasing the amount we pay to purchase power to supply POLR and default service obligations in the states we do business. In addition, the global economy could lead to lower international demand for coal, oil and natural gas, which may lower fossil fuel prices and put downward pressure on electricity prices.
Electricity and fuel prices may fluctuate substantially over relatively short periods of time for a variety of reasons, including:
changing weather conditions or seasonality;
changes in electricity usage by our customers;
illiquidity and credit worthiness of participants in wholesale power and other markets;
transmission congestion or transportation constraints, inoperability or inefficiencies;
availability of competitively priced alternative energy sources;
changes in supply and demand for energy commodities;
changes in power production capacity;
outages at our power production facilities or those of our competitors;
changes in production and storage levels of natural gas, lignite, coal, crude oil and refined products;
changes in legislation and regulation; and
natural disasters, wars, acts of sabotage, terrorist acts, embargoes and other catastrophic events.
We Are Exposed to Operational, Price and Credit Risks Associated With Selling and Marketing Products in the Power Markets That We Do Not Always Completely Hedge Against
We purchase and sell power at the wholesale level under market-based tariffs authorized by the FERC, and also enter into agreements to sell available energy and capacity from our generation assets. If we are unable to deliver firm capacity and energy under these agreements, we may be required to pay damages. These damages would generally be based on the difference between the market price to acquire replacement capacity or energy and the contract price of the prudence reviewundelivered capacity or energy. Depending on price volatility in the wholesale energy markets, such damages could be significant. Extreme weather conditions, unplanned power plant outages, transmission disruptions, and other factors could affect our ability to meet our obligations, or cause increases in the collectionmarket price of deferred costsreplacement capacity and energy.
We attempt to mitigate risks associated with satisfying our contractual power sales arrangements by reserving generation capacity to deliver electricity to satisfy our net firm sales contracts and, when necessary, by purchasing firm transmission service. We also routinely enter into contracts, such as fuel and power purchase and sale commitments, to hedge our exposure to fuel requirements and other energy-related commodities. We may not, however, hedge the entire exposure of our operations from commodity price


28


volatility. To the extent we do not hedge against commodity price volatility, our results of operations and financial position could be negatively affected.
The Use of Derivative Contracts by Us to Mitigate Risks Could Result in Financial Losses That May Negatively Impact Our Financial Results
We use a variety of non-derivative and derivative instruments, such as swaps, options, futures and forwards, to manage our commodity and financial market risks. In the absence of actively quoted market prices and pricing information from external sources, the valuation of some of these derivative instruments involves management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of some of these contracts. Also, we could recognize financial losses as a result of volatility in the market values of these contracts or if a counterparty fails to perform.
Financial Derivatives Reforms Could Increase Our Liquidity Needs and Collateral Costs and Impose Additional Regulatory Burdens
In July 2010, federal legislation was enacted to reform financial markets that were approvedsignificantly alter how OTC derivatives are regulated. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank) increased regulatory oversight of OTC derivatives, including (1) requiring standardized OTC derivatives to be traded on registered exchanges regulated by the CFTC, (2) imposing new and potentially higher capital and margin requirements and (3) authorizing the establishment of overall volume and position limits. The law gives the CFTC authority to exempt companies that participate in prior proceedings. On February 26, 2009, the Ohio Companies filed a Supplemental Stipulation,swap market as “end users” for hedging purposes which was signed orcould reduce, but not opposed by virtually alleliminate, the applicability of these measures to us. These requirements could cause our OTC transactions to be more costly and have an adverse effect on our liquidity due to additional capital requirements. In addition, as these reforms aim to standardize OTC products it could limit the partieseffectiveness of our hedging programs because we would have less ability to tailor OTC derivatives to match the proceeding, that supplemented and modified certain provisions of the February 19, 2009 Stipulation and Recommendation. Specifically, the Supplemental Stipulation modified the provision relatingprecise risk we are seeking to governmental aggregation and the Generation Service Uncollectible Rider, provided further detailprotect.
We rely on the allocationOTC derivative markets as part of our program to hedge the economic development funding containedprice risk associated with our power portfolio. The effect on our operations of this legislation will depend in part on whether we are determined to be a swap dealer, a major swap participant or a qualifying end-user through a self-identification process, based on the meaning of those terms to be established in the Stipulation and Recommendation, and proposed additional provisions relatedfinal rules. If we are determined to the collaborative process for the development of energy efficiency programs, among other provisions. The PUCO adopted and approved certain aspects of the Stipulation and Recommendation on March 4, 2009, and adopted and approved the remainder of the Stipulation and Recommendation and Supplemental Stipulation without modification on March 25, 2009. Certain aspects of the Stipulation and Recommendation and Supplemental Stipulation took effect on April 1, 2009 while the remaining provisions took effect on June 1, 2009.

The CBP auction occurred on May 13-14, 2009, and resulted inbe a weighted average wholesale price for generation and transmission of 6.15 cents per KWH. The bid was forswap dealer or 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). Subsequentmajor swap participant, we will be required to the signing of the wholesale contracts, four winning bidders reached separate agreements with FESregister with the result that FES is now responsible for providing 77 percent of the Ohio Companies’ total load supply.  The results of the CBP were accepted by the PUCO on May 14, 2009. FES has also separately contracted with numerous communitiesCFTC and execute most bilateral OTC derivative transactions through an exchange or central clearinghouse. This requirement could require us to provide retail generation service through governmental aggregation programs.

On July 27, 2009, the Ohio Companies filed applications with the PUCOcommit substantial additional capital to recover three different categories of deferred distribution costs on an accelerated basis. In the Ohio Companies' Amended ESP, the PUCO approved the recovery of these deferrals, with collection originally set to begincover increases 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 totaled $305.1 million. The applications were approved by the PUCO on August 19, 2009. Recovery of this amount, together with carrying charges calculated as approved in the Amended ESP, commenced on September 1, 2009, and will be collected in the 18 non-summer months from September 2009 through May 2011, subject to reconciliation until fully collected, with $165 million of the above amount being recovered from residential customers, and $140.1 million being recovered from non-residential customers.

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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 .75% reduction each year thereafter through 2018. The PUCO may amend these benchmarks in certain, limited circumstances, and the Ohio Companies have filed an application with the PUCO seeking such amendments. On January 7, 2010, the PUCO amended the 2009 energy efficiency benchmarks to zero, contingent upon the Ohio Companies meeting the revised benchmarks in a period of not more than three years.  The PUCO has not yet acted upon the application seeking a reduction of the peak demand reduction requirements. 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. 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. The PUCO has set the matter for hearing on March 2, 2010. The Ohio Companies expect that allcollateral costs associated with compliance willmargin requirements of the major exchanges. We would also be recoverable from customers.required to comply with increased reporting and record-keeping requirements and follow CFTC-specified business conduct standards, and adhere to position limits in a potentially broad range of energy commodities.

In October 2009, the PUCO issued additional Entries modifying certain of its previous rules that set out the manner in which electric utilities, including the Ohio Companies,Even if we are not determined to be a swap dealer or a major swap participant, we will be required to comply with benchmarks containedadditional regulatory obligations under Dodd-Frank, which includes some reporting requirements, clearing some additional transactions that we would otherwise enter into over-the-counter, and having to adhere to position limits. Also, the total burden that the rules could impose on all market participants could cause liquidity in SB221the bilateral OTC swap market to decrease substantially. The new rules could impede our ability to meet our hedge targets in a cost-effective manner. FirstEnergy cannot predict the ultimate outcome that Dodd-Frank will have on its results of operations, cash flows or financial position.
Our Risk Management Policies Relating to Energy and Fuel Prices, and Counterparty Credit, Are by Their Very Nature Risk Related, and We Could Suffer Economic Losses Despite Such Policies
We attempt to mitigate the market risk inherent in our energy, fuel and debt positions. Procedures have been implemented to enhance and monitor compliance with our risk management policies, including validation of transaction and market prices, verification of risk and transaction limits, sensitivity analysis and daily portfolio reporting of various risk measurement metrics. Nonetheless, we cannot economically hedge all of our exposures in these areas and our risk management program may not operate as planned. For example, actual electricity and fuel prices may be significantly different or more volatile than the historical trends and assumptions reflected in our analyses. Also, our power plants might not produce the expected amount of power during a given day or time period due to weather conditions, technical problems or other unanticipated events, which could require us to make energy purchases at higher prices than the prices under our energy supply contracts. In addition, the amount of fuel required for our power plants during a given day or time period could be more than expected, which could require us to buy additional fuel at prices less favorable than the prices under our fuel contracts. As a result, we cannot always predict the impact that our risk management decisions may have on us if actual events lead to greater losses or costs than our risk management positions were intended to hedge.
Our risk management activities, including our power sales agreements with counterparties, rely on projections that depend heavily on judgments and assumptions by management of factors such as future market prices and demand for power and other energy-related commodities. These factors become more difficult to predict and the calculations become less reliable the further into the future these estimates are made. Even when our policies and procedures are followed and decisions are made based on these estimates, results of operations may be diminished if the judgments and assumptions underlying those calculations prove to be inaccurate.
We also face credit risks from parties with whom we contract who could default in their performance, in which cases we could be forced to sell our power into a lower-priced market or make purchases in a higher-priced market than existed at the time of executing


29


the contract. Although we have established risk management policies and programs, including credit policies to evaluate counterparty credit risk, there can be no assurance that we will be able to fully meet our obligations, that we will not be required to pay damages for failure to perform or that we will not experience counterparty non-performance or that we will collect for voided contracts. If counterparties to these arrangements fail to perform, we may be forced to enter into alternative hedging arrangements or honor underlying commitments at then-current market prices. In that event, our financial results could be adversely affected.
Nuclear Generation Involves Risks that Include Uncertainties Relating to Health and Safety, Additional Capital Costs, the Adequacy of Insurance Coverage and Nuclear Plant Decommissioning
We are subject to the risks of nuclear generation, including but not limited to the following:
the potential harmful effects on the environment and human health resulting from unplanned radiological releases associated with the operation of our nuclear facilities and the storage, handling and disposal of radioactive materials;
limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with our nuclear operations or those of others in the United States;
uncertainties with respect to contingencies and assessments if insurance coverage is inadequate; and
uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed operation including increases in minimum funding requirements or costs of completion.
The NRC has broad authority under federal law to impose licensing security and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines and/or shut down a unit, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants, including ours. Also, a serious nuclear incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or relicensing of any domestic nuclear unit. See "Potential NRC Regulation in Response to the Incident at Japan's Fukushima Daiichi Nuclear Plant Could Adversely Effect Our Business and Financial Condition" below and Note 16, Commitments, Guarantees and Contingencies - Environmental Matters of the Combined Notes to the Consolidated Financial Statements.
We Have a Significant Percentage of Coal-Fired Generation Capacity Which Exposes us to Risk from Regulations Relating to Coal and Coal Combustion Residuals
Approximately 65% of FirstEnergy's generation fleet capacity is coal-fired. Historically, coal-fired generating plants face greater exposure to the costs of complying with federal, state and local environmental statutes, rules and regulations relating to emissions of SO2 and NOx. In addition, the MATS established coal-fired emission standards for mercury, hydrochloric acid and various metals effective in April 2015, proposed coal combustion residual regulations include an option to reclassify coal ash as a hazardous waste, and there are currently a number of federal, state and international initiatives under consideration to, among other things, require reductions in GHG emissions. These legal requirements and initiatives could require substantial additional costs, extensive mitigation efforts and, in the case of GHG requirements, could raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities. Failure to comply with any such existing or future legal requirements may also result in the assessment of fines and penalties. Significant resources also may be expended to defend against allegations of violations of any such requirements.
Capital Market Performance and Other Changes May Decrease the Value of Pension Fund Assets, Decommissioning and Other Trust Funds Which Then Could Require Significant Additional Funding
Our financial statements reflect the values of the assets held in trust to satisfy our obligations to decommission our nuclear generation facilities and under pension and other postemployment benefit plans. The value of certain of the assets held in these trusts do not have readily determinable market values. Changes in the estimates and assumptions inherent in the value of these assets could affect the value of the trusts. If the value of the assets held by the trusts declines by a material amount, our funding obligation to the trusts could materially increase. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. Forecasting investment earnings and costs to decommission nuclear generating stations, to pay future pensions and other obligations requires significant judgment, and actual results may differ significantly from current estimates. Capital market conditions that generate investment losses or increase the present value of liabilities can negatively impact our results of operations and financial position.
We Could be Subject to Higher Costs and/or Penalties Related to Mandatory Reliability Standards Set by NERC/FERC or Changes in the Rules of Organized Markets and the States in Which We Do Business
As a result of the EPACT, owners, operators, and users of the bulk electric system are subject to mandatory reliability standards promulgated by the NERC and approved by FERC as well as mandatory reliability standards and energy efficiency requirements imposed by each of the states in which we operate. The standards are based on the functions that need to be performed to ensure that the bulk electric system operates reliably. Compliance with modified or new reliability standards may subject us to higher operating costs and/or increased capital expenditures. If we were found not to be in compliance with the mandatory reliability


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standards, we could be subject to sanctions, including substantial monetary penalties.
Reliability standards that were historically subject to voluntary compliance are now mandatory and could subject us to potential civil penalties for violations which could negatively impact our business. The FERC can now impose penalties of $1.0 million per day for failure to comply with these mandatory electric reliability standards.
In addition to direct regulation by the FERC and the states, we are also subject to rules and terms of participation imposed and administered by various RTOs and ISOs. Although these entities are themselves ultimately regulated by the FERC, they can impose rules, restrictions and terms of service that are quasi-regulatory in nature and can have a material adverse impact on our business. For example, the independent market monitors of ISOs and RTOs may impose bidding and scheduling rules to curb the potential exercise of market power and to ensure the market functions. Such actions may materially affect our ability to sell, and the price we receive for, our energy and capacity. In addition, the RTOs may direct our transmission owning affiliates to build new transmission facilities to meet the reliability requirements of the RTO or to provide new or expanded transmission service under the RTO tariffs.
We Rely on Transmission and Distribution Assets That We Do Not Own or Control to Deliver Our Wholesale Electricity. If Transmission is Disrupted, Including Our Own Transmission, or Not Operated Efficiently, or if Capacity is Inadequate, Our Ability to Sell and Deliver Power May Be Hindered
We depend on transmission and distribution facilities owned and operated by utilities and other energy companies to deliver the electricity we sell. If transmission is disrupted (as a result of weather, natural disasters or other reasons) or not operated efficiently by ISOs, in applicable markets, or if capacity is inadequate, our ability to sell and deliver products and satisfy our contractual obligations may be hindered, or we may be unable to sell products on the most favorable terms. In addition, in certain of the markets in which we operate, we may be required to pay for congestion costs if we schedule delivery of power between congestion zones during periods of high demand. If we are unable to hedge or recover for such congestion costs in retail rates, our financial results could be adversely affected.
Demand for electricity within our Utilities’ service areas could stress available transmission capacity requiring alternative routing or curtailing electricity usage that may increase operating costs or reduce revenues with adverse impacts to our results of operations. In addition, as with all utilities, potential concerns over transmission capacity could result in MISO, PJM or the FERC requiring us to upgrade or expand our transmission system, requiring additional capital expenditures.
The FERC requires wholesale electric transmission services to be offered on an open-access, non-discriminatory basis. Although these regulations are designed to encourage competition in wholesale market transactions for electricity, it is possible that fair and equal access to transmission systems will not be available or that sufficient transmission capacity will not be available to transmit electricity as we desire. We cannot predict the timing of industry changes as a result of these initiatives or the adequacy of transmission facilities in specific markets or whether independent system operators in applicable markets will operate the transmission networks, and provide related services, efficiently.
Disruptions in Our Fuel Supplies or Changes in Our Fuel Needs Could Occur, Which Could Adversely Affect Our Ability to Operate Our Generation Facilities or Impact Financial Results

We purchase fuel from a number of suppliers. The lack of availability of fuel at expected prices, or a disruption in the delivery of fuel which exceeds the duration of our on-site fuel inventories, including disruptions as a result of weather, increased transportation costs or other difficulties, labor relations or environmental or other regulations affecting our fuel suppliers, could cause an adverse impact on our ability to operate our facilities, possibly resulting in lower sales and/or higher costs and thereby adversely affect our results of operations. Operation of our coal-fired generation facilities is highly dependent on our ability to procure coal. We have long-term contracts in place for a majority of our coal and coal transportation needs. We may from time to time enter into new, or renegotiate certain of these contracts, but can provide no assurance that such contracts will be negotiated or renegotiated, as the case may be, on satisfactory terms, or at all. In addition, if prices for physical delivery are unfavorable, our financial condition, results of operations and cash flows could be materially adversely affected.

Temperature Variations as well as Weather Conditions or other Natural Disasters Could Have a Negative Impact on Our Results of Operations and Demand Significantly Below or Above Our Forecasts Could Adversely Affect Our Energy Margins
Weather conditions directly influence the demand for electric power. Demand for power generally peaks during the summer and winter months, with market prices also typically peaking at that time. Overall operating results may fluctuate based on weather conditions. In addition, we have historically sold less power, and consequently received less revenue, when weather conditions are milder. Severe weather, such as tornadoes, hurricanes, ice or snowstorms, or droughts or other natural disasters, may cause outages and property damage that may require us to incur additional costs that are generally not insured and that may not be recoverable from customers. The effect of the failure of our facilities to operate as planned under these conditions would be particularly burdensome during a peak demand period.
Customer demand could change as a result of severe weather conditions or other circumstances over which we have no control. We satisfy our electricity supply obligations through a portfolio approach of providing electricity from our generation assets, contractual relationships and market purchases. A significant increase in demand could adversely affect our energy margins if we are required to provide the energy supply to fulfill this increased demand at fixed rates, which we expect would remain below the


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wholesale prices at which we would have to purchase the additional supply if needed or, if we had available capacity, the prices at which we could otherwise sell the additional supply. Accordingly, any significant change in demand could have a material adverse effect on our results of operations and financial position.
We Are Subject to Financial Performance Risks Related to Regional and General Economic Cycles and also Related to Heavy Manufacturing Industries such as Automotive and Steel
Our business follows economic cycles. Economic conditions are a determinant of the demand for electricity and declines in the demand for electricity will reduce our revenues. The regional economy in which our Utilities operate is influenced by conditions in automotive, steel and other heavy industries and as these conditions change, our revenues will be impacted. Additionally, the primary market areas of our Competitive Energy Services segment overlap, to a large degree, with our Utilities' territories and hence its revenues are impacted by the same economic conditions.
Increases in Customer Electric Rates and Economic Uncertainty May Lead to a Greater Amount of Uncollectible Customer Accounts
Our operations are impacted by the economic conditions in our service territories and those conditions could negatively impact the rate of delinquent customer accounts and our collections of accounts receivable which could adversely impact our financial condition, results of operations and cash flows.
We May Recognize Impairments of Recorded Goodwill or of Some of Our Long-Lived Assets, Which Would Result in Write-Offs of the Impaired Amounts
Goodwill could become impaired at one or more of our operating subsidiaries. In addition, one or more of our long-lived assets could become impaired. The actual timing and amounts of any impairments in future years would depend on many factors, including interest rates, sector market performance, our capital structure, market prices for power, results of future rate proceedings, operating and capital expenditure requirements, the value of comparable acquisitions, environmental regulations and other factors.
We Face Certain Human Resource Risks Associated with the Availability of Trained and Qualified Labor to Meet Our Future Staffing Requirements
We must find ways to balance the retention of our aging skilled workforce while recruiting new talent to mitigate losses in critical knowledge and skills due to retirements. Mitigating these risks could require additional financial commitments.
Significant Increases in Our Operation and Maintenance Expenses, Including Our Health Care and Pension Costs, Could Adversely Affect Our Future Earnings and Liquidity
We continually focus on limiting, and reducing where possible, our operation and maintenance expenses. We expect to continue to face increased cost pressures in the areas of health care and pension costs. We have experienced significant health care cost inflation in the last few years, and we expect our cash outlay for health care costs, including prescription drug coverage, to continue to increase despite measures that we have taken and expect to take requiring employees and retirees to bear a higher portion of the costs of their health care benefits. The measurement of our expected future health care and pension obligations and costs is highly dependent on a variety of assumptions, many of which relate to factors beyond our control. These assumptions include investment returns, interest rates, health care cost trends, benefit design changes, salary increases, the demographics of plan participants and regulatory requirements. If actual results differ materially from our assumptions, our costs could be significantly increased.
Our Results May be Adversely Affected by the Volatility in Pension and OPEB Expenses.
Effective in 2011, FirstEnergy elected to change its method of recognizing actuarial gains and losses of its pension and OPEB plans. This change will result in the recognition of net actuarial gains or losses, without deferral, in the fourth quarter of each year and whenever a plan is determined to qualify for a remeasurement, may result in greater volatility in pension and OPEB expenses and may materially impact our results of operations under GAAP. For additional information, see Note 1, Organization, Basis of Presentation and Significant Accounting Policies of the Combined Notes to the Consolidated Financial Statements.
Security Breaches, Including Cyber Security Breaches, and Other Disruptions Could Compromise Critical and Proprietary Information and Expose Us to Liability, Which Would Cause our Business and Reputation to Suffer.
In the ordinary course of our business, we store sensitive data, intellectual property and proprietary information regarding our business, employees, customers, suppliers and business partners in our data centers and on our networks. The secure maintenance of this information is critical to our operations. Despite security measures we have employed with respect to this information, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings and regulatory penalties. It could also disrupt our business operations and damage our reputation, which could adversely affect our business.


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Acts of War or Terrorism Could Negatively Impact Our Business
The possibility that our infrastructure, such as electric generation, transmission and distribution facilities, or that of an interconnected company, could be direct targets of, or indirect casualties of, an act of war or terrorism, could result in disruption of our ability to generate, purchase, transmit or distribute electricity. Any such disruption could result in a decrease in revenues and additional costs to purchase electricity and to replace or repair our assets, which could have a material adverse impact on our results of operations and financial condition.
Capital Improvements and Construction Projects May Not be Completed Within Forecasted Budget, Schedule or Scope Parameters
Our business plan calls for extensive capital investments. We may be exposed to the risk of substantial price increases in the costs of labor and materials used in construction. We engage numerous contractors and enter into a large number of agreements to acquire the necessary materials and/or obtain the required construction-related services. As a result, we are also exposed to the risk that these contractors and other counterparties could breach their obligations to us. Such risk could include our contractors’ inabilities to procure sufficient skilled labor as well as potential work stoppages by that labor force. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices, with resulting delays in those and other projects. Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than these mitigation provisions. This could have negative financial impacts such as incurring losses or delays in completing construction projects.
Changes in Technology May Significantly Affect Our Generation Business by Making Our Generating Facilities Less Competitive
We primarily generate electricity at large central facilities. This method results in economies of scale and lower costs than newer technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells. It is possible that advances in technologies will reduce their costs to levels that are equal to or below that of most central station electricity production, which could have a material adverse effect on our results of operations.
We May Acquire Assets That Could Present Unanticipated Issues for Our Business in the Future, Which Could Adversely Affect Our Ability to Realize Anticipated Benefits of Those Acquisitions
Asset acquisitions involve a number of risks and challenges, including: management attention; integration with existing assets; difficulty in evaluating the requirements associated with the assets prior to acquisition, operating costs, potential environmental and other liabilities, and other factors beyond our control; and an increase in our expenses and working capital requirements. Any of these factors could adversely affect our ability to achieve anticipated levels of cash flows or realize other anticipated benefits from any such asset acquisition.
Ability of Certain FirstEnergy Companies to Meet Their Obligations to or on behalf of Other FirstEnergy Companies or their Affiliates
Certain of the FirstEnergy companies have obligations to other FirstEnergy companies because of transactions involving energy, coal, other commodities, services and hedging transactions. If one FirstEnergy entity failed to perform under any of these arrangements, other FirstEnergy entities could incur losses. Their results of operations, financial position, or liquidity could be adversely affected, resulting in the nondefaulting FirstEnergy entity being unable to meet its obligations to unrelated third parties. Our hedging activities are generally undertaken with a view to overall FirstEnergy exposures. Some FirstEnergy companies may therefore be more or less hedged than if they were to engage in such transactions alone. Also, some companies affiliated with FirstEnergy also provide guarantees to third party creditors on behalf of other FirstEnergy affiliates under transactions of the type described above or under financing transactions. Any failure to perform under such a guarantee by the affiliated FirstEnergy guarantor company or under the underlying transaction by the FirstEnergy company on whose behalf the guarantee was issued could have similar adverse impacts on one or both FirstEnergy companies or their affiliates.
Energy Companies are Subject to Adverse Publicity Which Make Them Vulnerable to Negative Regulatory and Legislative Outcomes

Energy companies, including FirstEnergy's utility subsidiaries, have been the subject of criticism focused on the reliability of their distribution services and the speed with which they are able to respond to power outages, such as those caused by storm damage. Adverse publicity of this nature, or adverse publicity associated with our nuclear and/or coal-fired facilities may cause less favorable legislative and regulatory outcomes.
Our Merger with AE May Not Achieve Its Intended Results.

We entered into the merger agreement with AE with the expectation that the merger would result in various benefits, including, among other things, cost savings and operating efficiencies relating to the regulated business and the unregulated competitive business. Our ability to achieve the anticipated benefits of the merger is subject to a number of uncertainties, including whether the business and information systems of Allegheny are integrated in an efficient and effective manner. Failure to achieve these anticipated benefits could result in increased costs, decreases in the amount of expected revenues generated by us and diversion of management's time and energy and could have an adverse effect on our business, financial results and prospects. See Part II, Item 7, Management's Discussion and Analysis of Registrant and Subsidiaries for additional information.


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Risks Associated With Regulation
Complex and Changing Government Regulations, Including Those Associated With Rates Could Have a Negative Impact on Our Results of Operations
We are subject to comprehensive regulation by various federal, state and local regulatory agencies that significantly influence our operating environment. Changes in, or reinterpretations of, existing laws or regulations, or the imposition of new laws or regulations, could require us to incur additional costs or change the way we conduct our business, and therefore could have an adverse impact on our results of operations.
Our utility subsidiaries currently provide service at rates approved by one or more regulatory commissions. Thus, the rates a utility is allowed to charge may or may not be set to recover its expenses at any given time. Additionally, there may also be a delay between the timing of when costs are incurred and when costs are recovered. For example, we may be unable to timely recover the costs for our energy efficiency investments, expenses and additional capital or lost revenues resulting from the implementation of aggressive energy efficiency programs. While rate regulation is premised on providing an opportunity to earn a reasonable return on invested capital and recovery of operating expenses, there can be no assurance that the applicable regulatory commission will determine that all of our costs have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs in a timely manner.
Regulatory Changes in the Electric Industry, Including a Reversal of, Discontinuance of, or Impediment to the Present Trend Toward Competitive Markets, Could Affect Our Competitive Position and Result in Unrecoverable Costs Adversely Affecting Our Business and Results of Operations
As a result of restructuring initiatives, changes in the electric utility business have occurred, and are continuing to take place throughout the United States, including the states in which we do business. These changes have resulted, and are expected to continue to result, in fundamental alterations in the way utilities conduct their business.
Some states that have deregulated generation service have experienced difficulty in transitioning to market-based pricing. In some instances, state and federal government agencies and other interested parties have made proposals to impose rate cap extensions or otherwise impede market restructuring or even re-regulate areas of these markets that have previously been deregulated. Although we expect wholesale electricity markets to continue to be competitive, proposals to re-regulate our industry may be made, and legislative or other action affecting the electric power restructuring process may cause the process to be delayed, discontinued, restructured or reversed in the states in which we currently, or may in the future, operate. Such delays, discontinuations or reversals of electricity market restructuring in the markets in which we operate could have an adverse impact on our results of operations and financial condition.
The FERC and the U.S. Congress propose changes from time to time in the structure and conduct of the electric utility industry. If the restructuring, deregulation or re-regulation efforts result in decreased margins or unrecoverable costs, our business and results of operations would be adversely affected. We cannot predict the extent or timing of further efforts to restructure, deregulate or re-regulate our business or the industry.
The Prospect of Rising Rates Could Prompt Legislative or Regulatory Action to Restrict or Control Such Rate Increases. This In Turn Could Create Uncertainty Affecting Planning, Costs and Results of Operations and May Adversely Affect the Utilities’ Ability to Recover Their Costs, Maintain Adequate Liquidity and Address Capital Requirements
Increases in utility rates, such as may follow a period of frozen or capped rates, can generate pressure on legislators and regulators to take steps to control those increases. Such efforts can include some form of rate increase moderation, reduction or freeze. The public discourse and debate can increase uncertainty associated with the regulatory process, the level of rates and revenues, and the ability to recover costs. Such uncertainty restricts flexibility and resources, given the need to plan and ensure available financial resources. Such uncertainty also affects the costs of doing business. Such costs could ultimately reduce liquidity, as suppliers tighten payment terms, and increase costs of financing, as lenders demand increased compensation or collateral security to accept such risks.
Our Profitability is Impacted by Our Affiliated Companies’ Continued Authorization to Sell Power at Market-Based Rates
The FERC granted certain subsidiaries authority to sell electricity at market-based rates. These orders also granted them waivers of certain FERC accounting, record-keeping and reporting requirements. The FERC’s orders that grant this market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that these companies can exercise market power in transmission or generation, create barriers to entry or engage in abusive affiliate transactions. As a condition to the orders granting the generating companies market-based rate authority, every three years they are required to file a market power update to show that they continue to meet the FERC’s standards with respect to generation market power and other criteria used to evaluate whether entities qualify for market-based rates.
There Are Uncertainties Relating to Our Participation in RTOs
RTO rules could affect our ability to sell power produced by our generating facilities to users in certain markets due to transmission


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constraints and attendant congestion costs. The prices in day-ahead and real-time energy markets and RTO capacity markets have been subject to price volatility. Administrative costs imposed by RTOs, including the cost of administering energy markets, have also increased. The rules governing the various regional power markets may also change from time to time, which could affect our costs or revenues. To the degree we incur significant additional fees and increased costs to participate in an RTO, and we are limited with respect to recovery of such costs from retail customers, we may suffer financial harm. In addition, we may be allocated a portion of the cost of transmission facilities built by others due to changes in RTO transmission rate design. Finally, we may be required to expand our transmission system according to decisions made by an RTO rather than our internal planning process. As a member of an RTO, we are subject to certain additional risks, including those associated with the allocation among members of losses caused by unreimbursed defaults of other participants in that RTO’s market and those associated with complaint cases filed against the RTO that may seek refunds of revenues previously earned by its members.
Because it remains unclear which companies will be participating in the various regional power markets, or how RTOs will ultimately develop and operate, or what region they will cover, we cannot fully assess the impact that these power markets or other ongoing RTO developments may have.
Energy Conservation and Energy Price Increases Could Negatively Impact Our Financial Results
A number of regulatory and legislative bodies have introduced requirements and/or incentives to reduce energy consumption. Conservation programs could impact our financial results in different ways. To the extent conservation resulted in reduced energy demand or significantly slowed the growth in demand, the value of our competitive generation and other unregulated business activities could be adversely impacted. We currently have energy efficiency riders in place to recover the cost of these programs either at or near a current recovery timeframe in the states we operate. In New Jersey, we recover the costs for energy efficiency programs through the SBC. Currently only Ohio has provisions for recovery of lost revenues. In our regulated operations, conservation could negatively impact us depending on the regulatory treatment of the associated impacts. Should we be required to invest in conservation measures that result in reduced sales from effective conservation, regulatory lag in adjusting rates for the impact of these measures could have a negative financial impact. We could also be impacted if any future energy price increases result in a decrease in customer usage. Our results could be affected if we are unable to increase our customer’s participation in our energy efficiency programs. We are unable to determine what impact, if any, conservation and increases in energy prices will have on our financial condition or results of operations.
Our Business and Activities are Subject to Extensive Environmental Requirements and Could be Adversely Affected by such Requirements
We plan to retire nine older coal-fired generating plants by September 1, 2012, as a result of a comprehensive review of FirstEnergy's coal-fired generating facilities in light of the MATS rules that were recently finalized and other environmental requirements. We may be forced to shut down other facilities, either temporarily or permanently, if we are unable to comply with certain environmental requirements, or if we make a determination that the expenditures required to comply with such requirements are uneconomical.
The EPA is Conducting NSR Investigations at a Number of Generating Plants that We Currently or Formerly Owned, the Results of Which Could Negatively Impact Our Results of Operations and Financial Condition
We may be subject to risks in connection with changing or conflicting interpretations of existing laws and regulations, including, for example, the applicability of EPA's NSR programs . Under the CAA, modification of our generation facilities in a manner that results in increased emissions could subject our existing facilities to the far more stringent NSR standards applicable to new facilities.
The EPA has taken the view that many companies, including many energy producers, have been modifying emissions sources in violation of NSR standards in connection with work considered by the companies to be routine maintenance. We are currently involved in litigation and EPA investigations concerning alleged violations of the NSR standards at certain of our existing and former generating facilities. We intend to vigorously pursue and defend our position but we are unable to predict their outcomes. If NSR and similar requirements are imposed on our generation facilities, in addition to the possible imposition of fines, compliance could entail significant capital investments in pollution control technology, which could have an adverse impact on our business, results of operations, cash flows and financial condition. For a more complete discussion see Note 16, Commitments, Guarantees and Contingencies - Environmental Matters of the Combined Notes to the Consolidated Financial Statements.
Costs of Compliance with Environmental Laws are Significant, and the Cost of Compliance with Future Environmental Laws, Including Limitations on GHGEmissions, Could Adversely Affect Cash Flow and Profitability

Our operations are subject to extensive federal, state and local environmental statutes, rules and regulations. Compliance with these legal requirements requires us to incur costs for among other things, installation and operation of pollution control equipment, emission monitoring and fees, remediation and permitting at our facilities. These expenditures have been significant in the past and may increase in the future. If the cost of compliance with existing environmental laws and regulations does increase, it could adversely affect our business and results of operations, financial position and cash flows. Moreover, new environmental laws or regulations or changes to existing environmental laws or regulations may materially increase our costs of compliance or accelerate the timing of capital expenditures. Because of the deregulation of generation, we may not directly recover through rates additional costs incurred for such compliance. Our compliance strategy, although reasonably based on available information, may not successfully address future relevant standards and interpretations. If we fail to comply with environmental laws and regulations or


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new interpretations of longstanding requirements, even if caused by factors beyond our control, that failure could result in the assessment of civil or criminal liability and fines. In addition, any alleged violation of environmental laws and regulations may require us to expend significant resources to defend against any such alleged violations.

There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. Environmental advocacy groups, other organizations and some agencies in the United States and elsewhere are focusing considerable attention on carbon dioxide emissions from power generation facilities and their potential role in climate change. There is a growing consensus in the United States and globally that GHG emissions are a major cause of global warming and that some form of regulation will be forthcoming at the federal level with respect to GHG emissions (including CO2) and such regulation could result in the creation of substantial additional costs in the form of taxes or emission allowances. As a result, it is possible that state and federal regulations will be developed that will impose more stringent limitations on emissions than are currently in effect. Due to the uncertainty of control technologies available to reduce GHG emissions, including CO2, as well as the unknown nature of potential compliance obligations should climate change regulations be enacted, we cannot provide any assurance regarding the potential impacts these future regulations would have on our operations. In addition, any legal obligation that would require us to substantially reduce our emissions could require extensive mitigation efforts and, in the case of carbon dioxide legislation, would raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities. Until specific regulations are issued, the impact that any new environmental regulations, voluntary compliance guidelines, enforcement initiatives, or legislation may have on our results of operations, financial condition or liquidity is not determinable.

FirstEnergy cannot currently estimate the financial impact of certain environmental laws or initiatives including climate change policies, but 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. See Note 16, Commitments, Guarantees and Contingencies - Environmental Matters of the Combined Notes to the Consolidated Financial Statements for a more detailed discussion of the federal, state and international initiatives seeking to reduce emissions of GHG.

We Could be Exposed to Private Rights of Action Seeking Damages Under Various State and Federal Law Theories

Claims have been made against certain energy companies alleging that CO2 emissions from power generating facilities constitute a public nuisance under federal and/or state common law. As a result, private individuals may seek to enforce environmental laws and regulations against us and could allege personal injury or property damages. While FirstEnergy is not a party to this litigation, it, and/or one of its subsidiaries, could be named in actions making similar allegations. An unfavorable ruling in any such case could have an adverse impact on our results of operations and financial condition and could significantly impact our operations.

Our Costs to Comply with Various Recently Adopted EPA Emission Regulations Could be Substantial and Result in Significant Changes to Our Operations

We are required to comply with recently adopted emission regulations. The EPA's CAIR and CSAPR require reductions of NOx and SO2 emissions in two phases, ultimately capping SO2 and NOx emissions in affected states. In July 2011, the EPA finalized the CSAPR (which was stayed in December 2011 pending a decision on various legal challenges) to replace CAIR, which remains in effect until CSAPR becomes effective.

Depending on the outcome of these legal proceedings and how any final rules are ultimately implemented, MP's, FGCO's and AE Supply's future cost of compliance may be substantial and changes to FirstEnergy's operations may result.

Additionally, on December 21, 2011, the EPA finalized the MATS to establish emission standards for, among other things, mercury, hydrochloric acid and various metals for electric generating units. The costs associated with MATS, and other environmental laws, is substantial and led to the Company's recent announcement to retire nine older coal-fired generating units. Depending on how the CSPAR and MATS are ultimately implemented, FirstEnergy's future cost of compliance with such regulations may be substantial and additional changes to FirstEnergy's operations may result. See Note 16, Commitments, Guarantees and Contingencies - Environmental Matters of the Combined Notes to the Consolidated Financial Statements for a more detailed discussion of the above-referenced EPA regulations.

Various Federal and State Water Quality Regulations May Require Us to Make Material Capital Expenditures

The EPA established performance standards under the Clean Water Act which requires the EPA to establish performance standards for reducing impacts on fish and shellfish from cooling water intake structures at certain existing electric generating plants, specifically, impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). In 2011, the EPA proposed new regulations under the Clean Water Act which generally require fish impingement to be reduced to a 12% annual average and calls for studies to be conducted at the majority of our existing generating facilities to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic life. FirstEnergy is studying the cost and effectiveness of various control options to divert fish away from its plants' cooling water intake system. Depending on the results of such studies and the EPA's further rulemaking and any final action taken by the states, the future costs of compliance with these standards may require material capital expenditures. See Note 16, Commitments, Guarantees and Contingencies - Environmental Matters of the Combined Notes to the Consolidated Financial Statements for a more detailed discussion of the various federal and state water


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quality regulations listed above.

Compliance with any Coal Combustion Residual Regulations Could Have an Adverse Impact on Our Results of Operations and Financial Condition

We are subject to various federal and state hazardous waste regulations. The EPA has requested comments from the states on options for regulating coal combustion residuals, including whether they should be regulated as hazardous or non-hazardous waste.

The EPA asserted that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry and has proposed two options for additional regulation of coal combustion residuals, including the option of regulation as a special waste under the EPA's hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. FirstEnergy's future cost of compliance with any coal combustion residuals regulations that may be issued could be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the EPA or the states. Compliance with those regulations could have an adverse impact on our results of operations and financial condition.
Remediation of Environmental Contamination at Current or Formerly Owned Facilities
We are subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we may have generated regardless of whether the liabilities arose before, during or after the time we owned or operated the facilities. Remediation activities associated with our former MGP operations are one source of such costs. We are currently involved in a number of proceedings relating to sites where other hazardous substances have been deposited and may be subject to additional proceedings in the future. We also have current or previous ownership interests in sites associated with the production of gas and the production and delivery of electricity for which we may be liable for additional costs related to investigation, remediation and monitoring of these sites. Citizen groups or others may bring litigation over environmental issues including claims of various types, such as property damage, personal injury, and citizen challenges to compliance decisions on the enforcement of environmental requirements, such as opacity and other air quality standards, which could subject us to penalties, injunctive relief and the cost of litigation. We cannot predict the amount and timing of all future expenditures (including the potential or magnitude of fines or penalties) related to such environmental matters, although we expect that they could be material.
In some cases, a third party who has acquired assets from us has assumed the liability we may otherwise have for environmental matters related to the employmenttransferred property. If the transferee fails to discharge the assumed liability or disputes its responsibility, a regulatory authority or injured person could attempt to hold us responsible, and our remedies against the transferee may be limited by the financial resources of the transferee.
We Are and May Become Subject to Legal Claims Arising from the Presence of Asbestos or Other Regulated Substances at Some of Our Facilities
We have been named as a defendant in pending asbestos litigation involving multiple plaintiffs and multiple defendants. In addition, asbestos and other regulated substances are, and may continue to be, present at our facilities where suitable alternative materials are not available. We believe that any remaining asbestos at our facilities is contained. The continued presence of asbestos and other regulated substances at these facilities, however, could result in additional actions being brought against us.
Availability and Cost of Emission Allowances Could Negatively Impact Our Costs of Operations

Although recent court rulings and current conditions have reduced the immediate risk of a negative impact on our operating costs, the uncertainty around CAA programs and requirements continue to be a major concern. We are still required to maintain, either by allocation or purchase, sufficient emission allowances to support our operations in the ordinary course of operating our power generation facilities. These allowances are used to meet our obligations imposed by various applicable environmental laws. If our operational needs require more than our allocated allowances, we may be forced to purchase such allowances on the open market, which could be costly. If we are unable to maintain sufficient emission allowances to match our operational needs, we may have to curtail our operations so as not to exceed our available emission allowances, or install costly new emissions controls. As we use the emissions allowances that we have purchased on the open market, costs associated with such purchases will be recognized as operating expense. If such allowances are available for purchase, but only at significantly higher prices, the purchase of such allowances could materially increase our costs of operations in the affected markets.
Mandatory Renewable Portfolio Requirements Could Negatively Affect Our Costs
If federal or state legislation mandates the use of renewable and alternative fuel sources, such as wind, solar, biomass and geothermal and such legislation would not also provide for adequate cost recovery, it could result in significant changes in our business, including renewable energy resources,credit purchase costs, purchased power and potentially renewable energy efficiency/peak demand reduction programscredit costs and capital expenditures. We are unable to predict what impact, if any, these changes may have on our financial condition or results of operations.
The Continuing Availability and Operation of Generating Units is Dependent on Retaining or Renewing the Necessary Licenses, Permits, and Operating Authority from Governmental Entities, Including the NRC


37


We are required to have numerous permits, approvals and certificates from the agencies that regulate our business. We believe the necessary permits, approvals and certificates have been obtained for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from future regulatory activities of any of these agencies and we are not assured that any such permits, approvals or certifications will be renewed.
Potential NRC Regulation in Response to the Incident at Japan's Fukushima Daiichi Nuclear Plant Could Adversely Effect Our Business and Financial Condition

As a result of the NRC's investigation of the incident at the Fukushima Daiichi nuclear plant, potential exists for the NRC to promulgate new or revised requirements with respect to nuclear plants located in the United States, which could necessitate additional expenditures at our nuclear plants. For example, as a follow up to the NRC near-term Task Force's review and analysis of the Fukushima Daiichi accident, in January 2012, the NRC released an updated seismic risk model that plant operators must use in performing the seismic reevaluations recommended by the task force. These reevaluations could result in the required implementation of additional mitigation strategies or modifications. It is also possible that the NRC could suspend or otherwise delay pending nuclear relicensing proceedings, including the Davis-Besse relicensing proceeding. The impact of any such regulatory actions could adversely affect FirstEnergy's financial condition or results of operations.
The Physical Risks Associated with Climate Change May Impact Our Results of Operations and Cash Flows
Physical risks of climate change, such as more frequent or more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, and other related phenomena, could affect some, or all, of our operations. Severe weather or other natural disasters could be destructive, which could result in increased costs, including supply chain costs. An extreme weather event within the Utilities' service areas can also directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment. Finally, climate change could affect the availability of a secure and economical supply of water in some locations, which is essential for continued operation of generating plants.
Future Changes in Accounting Standards May Affect Our Reported Financial Results
The SEC, FASB or other authoritative bodies or governmental entities may issue new pronouncements or new interpretations of existing accounting standards that may require us to change our accounting policies. These changes are beyond our control, can be difficult to predict and could materially impact how we report our financial condition and results of operations. We could be required to apply a new or revised standard retroactively, which could adversely affect our financial position. The SEC announced a work plan to aid in its evaluation of the impact that the use of IFRS by U.S. public companies would have on the U.S. securities market and has identified several potential options to incorporate IFRS in the United States. The SEC expects to announce a more specific course of action in 2012. We continue to monitor the development of the potential implementation of IFRS.
Increases in Taxes and Fees May Adversely Effect Our Results of Operation, Financial Audit and Cash Flow
Due to the revenue needs of the United States and the states and jurisdictions in which we operate, various tax and fee increases may be proposed or considered. We cannot predict whether legislation or regulation will be introduced, the form of any legislation or regulation, whether any such legislation or regulation will be passed by legislatures or regulatory bodies. If enacted, these changes could increase tax costs and could have a negative impact on our results of operations, financial condition and cash flows.
Risks Associated With Financing and Capital Structure
Disruptions in the Capital and Credit Markets May Adversely Affect Our Business, Including the Availability and Cost of Short-Term Funds for Liquidity Requirements, Our Ability to Meet Long-Term Commitments, Our Ability to Hedge Effectively Our Generation Portfolio, and the Competitiveness and Liquidity of Energy Markets; Each Could Adversely Affect Our Results of Operations, Cash Flows and Financial Condition
We rely on the capital markets to meet our financial commitments and short-term liquidity needs if internal funds are not available from our operations. We also use letters of credit provided by various financial institutions to support our hedging operations. Disruptions in the capital and credit markets could adversely affect our ability to draw on our respective credit facilities. Our access to funds under those credit facilities is dependent on the ability of the financial institutions that are parties to the facilities to meet their funding commitments. Those institutions may not be able to meet their funding commitments if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests within a short period of time.
Longer-term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant financial institutions could adversely affect our access to liquidity needed for our business. Any disruption could require us to take measures to conserve cash until the markets stabilize or until alternative credit arrangements or other funding for our business needs can be arranged. Such measures could include deferring capital expenditures, changing hedging strategies to reduce collateral-posting requirements, and reducing or eliminating future dividend payments or other discretionary uses of cash.
The strength and depth of competition in energy markets depends heavily on active participation by multiple counterparties, which


38


could be adversely affected by disruptions in the capital and credit markets. Reduced capital and liquidity and failures of significant institutions that participate in the energy markets could diminish the liquidity and competitiveness of energy markets that are important to our business. Perceived weaknesses in the competitive strength of the energy markets could lead to pressures for greater regulation of those markets or attempts to replace those market structures with other mechanisms for the sale of power, including the requirement of long-term contracts, which could have a material adverse effect on our results of operations and cash flows.
Interest Rates and/or a Credit Rating Downgrade Could Negatively Affect Our Financing Costs, Our Ability to Access Capital and Our Requirement to Post Collateral
We have near-term exposure to interest rates from outstanding indebtedness indexed to variable interest rates, and we have exposure to future interest rates to the extent we seek to raise debt in the capital markets to meet maturing debt obligations and fund construction or other investment opportunities. Past disruptions in capital and credit markets have resulted in higher interest rates on new publicly issued debt securities, increased costs for certain of our variable interest rate debt securities and failed remarketings of variable interest rate tax-exempt debt issued to finance certain of our facilities. Similar future disruptions could increase our financing costs and adversely affect our results of operations. Also, interest rates could change as a result of economic or other events that our risk management processes were not established to address. As a result, we cannot always predict the impact that our risk management decisions may have on us if actual events lead to greater losses or costs than our risk management positions were intended to hedge. Although we employ risk management techniques to hedge against interest rate volatility, significant and sustained increases in market interest rates could materially increase our financing costs and negatively impact our reported results of operations.
We rely on access to bank and capital markets as sources of liquidity for cash requirements not satisfied by cash from operations. A downgrade in our credit ratings from the nationally recognized credit rating agencies, particularly to a level below investment grade, could negatively affect our ability to access the bank and capital markets, especially in a time of uncertainty in either of those markets, and may require us to post cash collateral to support outstanding commodity positions in the wholesale market, as well as greenhouse gas reportingavailable letters of credit and other guarantees. Furthermore, a downgrade could increase the cost of such capital by causing us to incur higher interest rates and fees associated with such capital. A rating downgrade would also increase the fees we pay on our various existing credit facilities, thus increasing the cost of our working capital. A rating downgrade could also impact our ability to grow our businesses by substantially increasing the cost of, or limiting access to, capital. See Note 16, Commitments, Guarantees and Contingencies - Guarantees and Other Assurances of the Combined Notes to the Consolidated Financial Statements for more information associated with a credit ratings downgrade leading to the posting of cash collateral.
The Soundness of Financial Institutions or Counterparties Could Adversely Affect Us
We have exposure to many different domestic and foreign financial institutions and counterparties and we routinely execute transactions with counterparties in connection with our hedging activities, including brokers and dealers, commercial banks, investment banks and other institutions and industry participants. Many of these transactions expose us to credit risk in the event that any of our lenders or counterparties are unable to honor their commitments or otherwise default under a financing agreement. We also deposit cash balances in short-term investments. Our ability to access our cash quickly depends on the soundness of the financial institutions in which those funds reside. Any delay in our ability to access those funds, even for a short period of time, could have a material adverse effect on our results of operations and financial condition.
We Must Rely on Cash from Our Subsidiaries and Any Restrictions on Our Utility Subsidiaries' Ability to Pay Dividends or Make Cash Payments to Us May Adversely Affect Our Financial Condition
We are a holding company and our investments in our subsidiaries are our primary assets. Substantially all of our business is conducted by our subsidiaries. Consequently, our cash flow is dependent on the operating cash flows of our subsidiaries and their ability to upstream cash to the holding company. Our utility subsidiaries are regulated by various state utility commissions that generally possess broad powers to ensure that the needs of utility customers are being met. Those state commissions could attempt to impose restrictions on the ability of our utility subsidiaries to pay dividends or otherwise restrict cash payments to us.
We Cannot Assure Common Shareholders that Future Dividend Payments Will be Made, or if Made, in What Amounts they May be Paid

Our Board of Directors regularly evaluates our common stock dividend policy and determines the dividend rate each quarter. The level of dividends will continue to be influenced by many factors, including, among other things, our earnings, financial condition and cash flows from subsidiaries, as well as general economic and competitive conditions. We cannot assure common shareholders that dividends will be paid in the future, or that, if paid, dividends will be at the same amount or with the same frequency as in the past.
ITEM 1B.UNRESOLVED STAFF COMMENTS
None.


39


ITEM 2.PROPERTIES
The Ohio Companies', Penn's, FGCO’s and NGC’s respective first mortgage indentures constitute direct first liens on substantially all of the respective physical property, subject only to excepted encumbrances, as defined in the first mortgage indentures. See Notes 6, Leases, and 12, Capitalization of the Combined Notes to the Consolidated Financial Statements for information concerning leases and financing encumbrances affecting certain of the Utilities’, FGCO’s and NGC’s properties.
FirstEnergy controls the following generation sources as of January 31, 2012, shown in the table below. Except for the leasehold interests, OVEC participation and wind power arrangements referenced in the footnotes to the table, substantially all FES' competitive generating units are owned by NGC (nuclear) and FGCO (non-nuclear); the regulated generating units are owned by JCP&L and MP.


40


      Competitive  
Plant (Location) Unit Total FES AE Supply Regulated
    Net Demonstrated Capacity (MW)
Super-critical Coal-fired:  
        
Bruce Mansfield (Shippingport, PA) 1
 830
(1) 
830
 —
 —
Bruce Mansfield (Shippingport, PA) 2
 830
(2) 
830
 —
 —
Bruce Mansfield (Shippingport, PA) 3
 830
(3) 
830
 —
 —
Harrison (Haywood, WV) 1-3
 1,984
 —
 1,576
 408
Hatfield's Ferry (Masontown, PA) 1-3
 1,710
 —
 1,710
 —
Pleasants (Willow Island, WV) 1-2
 1,300
 —
 1,200
 100
W. H. Sammis (Stratton, OH) 6-7
 1,200
  
1,200
 —
 —
Fort Martin (Maidsville, WV) 1-2
 1,107
 —
 —
 1,107
Eastlake (Eastlake, OH)(4)
 5
 597
 597
 —
 —
    10,388
 4,287
 4,486
 1,615
Sub-critical and Other Coal-fired:          
W. H. Sammis (Stratton, OH) 1-5
 1,020
  
1,020
 —
 —
Eastlake (Eastlake, OH)(4)
 1-4
 636
 636
 —
 —
Bay Shore (Toledo, OH) 1
 136
 136
    
Bay Shore (Toledo, OH)(4)
 2-4
 495
 495
 —
 —
Armstrong (Adrian, PA)(4)
 1-2
 356
 —
 356
 —
Albright (Albright, WV)(4)
 1-3
 292
 —
 —
 292
Mitchell (Courtney, PA) 3
 288
 —
 288
 —
Lakeshore (Cleveland, OH)(4)
 18
 245
 245
 —
 —
Ashtabula (Ashtabula, OH)(4)
 5
 244
 244
 —
 —
Willow Island (Willow Island, WV)(4)
 1-2
 242
 —
 —
 242
Rivesville (Rivesville, WV)(4)
 5-6
 126
 —
 —
 126
R. Paul Smith (Williamsport, MD)(4)
 3-4
 116
 —
 116
 —
R. E. Burger (Shadyside, OH) 3
 94
 94
 —
 —
OVEC (Cheshire, OH) (Madison, IN) 1-11
 188
(5) 
110
 67
 11
   
 4,478
  
2,980
 827
 671
Nuclear:  
  
  
     
Beaver Valley (Shippingport, PA) 1
 911
  
911
 —
 —
Beaver Valley (Shippingport, PA) 2
 904
(6) 
904
 —
 —
Davis-Besse (Oak Harbor, OH) 1
 908
  
908
 —
 —
Perry (N. Perry Village, OH) 1
 1,268
(7) 
1,268
 —
 —
   
 3,991
  
3,991
 —
 —
Gas/Oil-fired:  
  
  
     
AE Nos. 1, 2, 3, 4 & 5 (Springdale, PA) 1-5
 638
 —
 638
 —
West Lorain (Lorain, OH) 1-6
 545
  
—
 545
 —
AE Nos. 12 & 13 (Chambersburg, PA) 12-13
 88
 —
 88
 —
AE Nos. 8 & 9 (Gans, PA) 8-9
 88
 —
 88
 —
Mitchell (Courtney, PA) 2
 82
 —
 82
 —
Hunlock CT (Hunlock Creek, PA) 1
 45
 —
 45
 —
Buchanan (Oakwood, VA) 1-2
 43
(8) 
—
 43
 —
Other   216
 216
 —
 —
    1,745
 216
 1,529
 —
Pumped-storage and Hydro:  
  
  
     
Bath County (Warm Springs, VA) 1-6
 1,110
(9) 
—
 660
 450
Seneca (Warren, PA) 1-3
 451
  
451
 —
 —
Yard’s Creek (Blairstown Twp., NJ) 1-3
 200
(10) 
—
 —
 200
Lake Lynn (Lake Lynn, PA) 1-4
 52
(11) 
—
 52
  
Other   19
 —
 19
 —
    1,832
 451
 731
 650
Wind Power  
 376
(12) 
376
 —
 —
Total   22,810
 12,301
 7,573
 2,936


41


(1)
Includes FGCO’s leasehold interest of 93.825% (779 MW) and CEI’s leasehold interest of 6.175% (51 MW), which has been assigned to FGCO.
(2)
Includes CEI’s and TE’s leasehold interests of 27.17% (226 MW) and 16.435% (136 MW), respectively, which have been assigned to FGCO.
(3)
Includes CEI’s and TE’s leasehold interests of 23.247% (193 MW) and 18.915% (157 MW), respectively, which have been assigned to FGCO.
(4)
During the first quarter of 2012, FirstEnergy announced that these coal-fired plants will be retired by September 1, 2012, subject to review for reliability impacts by PJM.
(5)
Represents FGCO’s 4.85% and AE's 3.5% entitlement based on their participation in OVEC.
(6)
Includes OE’s leasehold interest of 16.65% (151 MW) from non-affiliates.
(7)
Includes OE’s leasehold interest of 8.11% (103 MW) from non-affiliates.
(8)
Buchanan Energy is a subsidiary of AE Supply. CNX Gas Corporation and Buchanan Energy have equal ownership interests in Buchanan Generation, LLC. AE Supply operates and dispatches 100% of Buchanan Generation, LLC's 86 MWs.
(9)
Represents capacity entitlement through ownership of AGC.
(10)
Represents JCP&L’s 50% ownership interest.
(11)
AE Supply has a license for Lake Lynn through 2024.
(12)
Includes 167 MW from leased facilities and 209 MW under power purchase agreements.
The above generating plants and load centers are connected by a transmission system consisting of elements having various voltage ratings ranging from 23 kV to 500 kV. The Utilities’ overhead and underground transmission lines aggregate 24,305 pole miles.
The Utilities’ electric distribution systems include 254,899 miles of overhead pole line and underground conduit carrying primary, secondary and street lighting circuits. They own substations with a total installed transformer capacity of approximately 140,158,000 kV-amperes.
All of FirstEnergy's generation, transmission and distribution assets operate in PJM.
FirstEnergy’s distribution and transmission systems as of December 31, 2011, consist of the following:
 
Distribution
Lines(1)
 
Transmission
Lines(1)
 
Substation
Transformer
Capacity(2)
   kV Amperes
OE62,238
 461
 7,763,000
Penn13,419
 52
 1,425,000
CEI33,252
 —
 8,938,000
TE17,593
 81
 3,040,000
JCP&L22,800
 2,550
 23,150,000
Met-Ed18,695
 1,406
 10,819,000
Penelec27,131
 2,909
 15,234,000
ATSI(3)
—
 7,524
 23,578,000
WP20,026
 4,419
 14,077,000
MP20,730
 2,625
 15,230,000
PE19,015
 2,126
 11,033,000
TrAIL(4)
—
 152
 5,871,000
Total254,899
 24,305
 140,158,000
(1)
Pole miles
(2)
Top rating of in-service power transformers only. Excludes grounding banks, station power transformers, and generator and customer-owned transformers.
(3)
Represents transmission lines of 69kV and above located in the service areas of OE, Penn, CEI and TE.
(4)
Represents transmission lines at 500kV located in the service areas of MP, PE and WP.
ITEM 3.LEGAL PROCEEDINGS
Reference is made to Note 16, Commitments, Guarantees and Contingencies of the Combined Notes to the Consolidated Financial Statements for a description of certain legal proceedings involving FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec.
ITEM 4.MINE SAFETY DISCLOSURE
Signal Peak Mine Safety
During 2011, FirstEnergy, through its FEV wholly owned subsidiary, held a 50% interest in Global Mining Group, LLC, a joint venture owning Signal Peak, which is a company that constructed and operates the Bull Mountain Mine No. 1 (Mine), an underground coal mine near Roundup Montana. The operation of the Mine is subject to regulation by the MSHA under the Mine Act.


42


On October 18, 2011, FirstEnergy announced that Gunvor Group, Ltd. signed an agreement to purchase a one-third interest in the Signal Peak coal mine in Montana. As a result of the sale, FirstEnergy, through its wholly owned subsidiary, FEV, currently has a 33-1/3% interest in Global Holding, a joint venture that owns Signal Peak.
Information concerning mine safety violations or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act is included in Exhibit 95 to this Annual Report on Form 10-K.
PART II
ITEM 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
The information required by Item 5 regarding FirstEnergy’s market information, including stock exchange listings and quarterly stock market prices, dividends and holders of common stock is included in Item 6.
Information for FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec is not disclosed because they are wholly owned subsidiaries of FirstEnergy and there is no market for their common stock.
Information regarding compensation plans for which shares of FirstEnergy common stock may be issued is incorporated herein by reference to FirstEnergy’s 2012 proxy statement to be filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.
The table below includes information on a monthly basis regarding purchases made by FE of its common stock during the fourth quarter of 2011.
  Period
  October November December Fourth Quarter
Total Number of Shares Purchased(1)
 112,225
 167,674
 712,539
 992,438
Average Price Paid per Share $44.36
 $44.32
 $44.19
 $44.23
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 —
 —
 —
 —
(1)
Share amounts reflect purchases on the open market to satisfy FirstEnergy's obligations to deliver common stock for some or all of the following: 2007 Incentive Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan, Director Compensation, Allegheny Energy, Inc. 1998 Long-Term Incentive Plan, Allegheny Energy, Inc. 2008 Long-Term Incentive Plan, Allegheny Energy, Inc, Non-Employee Director Stock Plan, Allegheny Energy, Inc, Amended and Restated Revised Plan for Deferral of Compensation of Directors, and Stock Investment Plan.
ITEM 6.SELECTED FINANCIAL DATA
For the Years Ended December 31, 2011 
2010(1)
 
2009(1)
 
2008(1)
 
2007(1)
  (In millions, except per share amounts)
Revenues $16,258
 $13,339
 $12,973
 $13,627
 $12,802
Earnings Available to FirstEnergy Corp.(2)
 $885
 $742
 $872
 $623
 $1,489
Earnings per Share of Common Stock:(2)
          
Basic $2.22
 $2.44
 $2.87
 $2.05
 $4.86
Diluted $2.21
 $2.42
 $2.85
 $2.03
 $4.80
Weighted Average Shares Outstanding:          
Basic 399
 304
 304
 304
 306
Diluted 401
 305
 306
 307
 310
Dividends Declared per Share of Common Stock(3)
 $2.20
 $2.20
 $2.20
 $2.20
 $2.05
Total Assets(4)
 $47,326
 $35,531
 $35,054
 $34,206
 $32,394
Capitalization as of December 31:          
Total Equity(5)
 $13,299
 $8,952
 $9,014
 $8,748
 $9,129
Long-Term Debt and Other Long-Term Obligations 15,716
 12,579
 12,008
 9,100
 8,869
Total Capitalization(5)
 $29,015
 $21,531
 $21,022
 $17,848
 $17,998
(1)
Reflects the retrospective change in recognizing pensions and OPEB costs.
(2)
The retrospective change in accounting for pensions and OPEB costs decreased Earnings Available to FirstEnergy Corp and Earnings Per Share (basic; diluted) as follows: 2010 - $42 million ($0.14; $0.15 per share), 2009 - $134 million ($0.44; $0.44 per share) and 2008 - $719


43


million ($2.36; $2.35 per share); and increased Earnings Available to FirstEnergy Corp. and Earnings Per Share (basic; diluted) in 2007 by $180 million ($0.59; $0.58 per share).
(3)
Dividends declared in 2011, 2010, 2009 and 2008 include four quarterly dividends of $0.55 per share. Dividends declared in 2007 include three quarterly payments of $0.50 per share in 2007 and one quarterly payment of $0.55 per share in 2008.
(4)
The retrospective change in accounting for pensions and OPEB costs increased Total Assets as of December 31 as follows: 2010 - $726 million, 2009 - $750 million, 2008 - $685 million and 2007 - $83 million.
(5)
The retrospective change in accounting for pensions and OPEB costs increased Total Equity as of December 31 as follows: 2010 - $439 million, 2009 - $457 million, 2008 - $433 million and 2007 - $122 million.
PRICE RANGE OF COMMON STOCK
The common stock of FirstEnergy Corp. is listed on the New York Stock Exchange under the symbol “FE” and is traded on other registered exchanges.
 2011 2010
 High Low High Low
First Quarter$40.80
 $36.11
 $47.09
 $38.31
Second Quarter$45.80
 $36.50
 $39.96
 $33.57
Third Quarter$46.51
 $38.77
 $39.06
 $34.51
Fourth Quarter$46.10
 $41.55
 $40.12
 $35.00
Yearly$46.51
 $36.11
 $47.09
 $33.57
Prices are from http://finance.yahoo.com.
SHAREHOLDER RETURN
The following graph shows the total cumulative return from a $100 investment on December 31, 2006 in FirstEnergy’s common stock compared with the total cumulative returns of EEI’s Index of Investor-Owned Electric Utility Companies and the S&P 500.
HOLDERS OF COMMON STOCK
There were 115,120 and 114,808 holders of 418,216,437 shares of FirstEnergy’s common stock as of December 31, 2011 and January 31, 2012, respectively. Information regarding retained earnings available for payment of cash dividends is given in Note 12, Capitalization of the Combined Notes to the Consolidated Financial Statements.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.


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ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT AND SUBSIDIARIES

Forward-Looking Statements: This Form 10-K 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.
The impact of the regulatory process on the pending matters before FERC in the various states in which we do business including, but not limited to, matters related to rates.
The status of the PATH project in light of PJM's direction to suspend work on the project pending review of its planning process, its re-evaluation of the need for the project and the uncertainty of the timing and amounts of any related capital expenditures.
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.
Financial derivative reforms that could increase our liquidity needs and collateral costs.
The continued ability of FirstEnergy's regulated utilities to collect transition and other costs.
Operation and maintenance costs being higher than anticipated.
Other legislative and regulatory changes, and revised environmental requirements, including possible GHG emission, water intake and coal combustion residual regulations, the potential impacts of any laws, rules or regulations that ultimately replace CAIR, including CSAPR which was stayed by the courts on December 30, 2011, and the effects of the EPA's MATS rules.
The uncertainty of the timing and amounts of the capital expenditures that may arise in connection with litigation, including NSR litigation or potential regulatory initiatives or rulemakings (including that such expenditures could result in our decision to shut down or idle certain generating units).
The uncertainty associated with the company's plan to retire its older unscrubbed regulated and competitive fossil units, including the impact on vendor commitments and PJM's review of the company's plans.
Adverse regulatory or legal decisions and outcomes with respect to our nuclear operations (including, but not limited to the revocation or non-renewal of necessary licenses, approvals or operating permits by the NRC including as a result of the incident at Japan's Fukushima Daiichi Nuclear Plant).
Issues that could result from our continuing investigation and analysis of the indications of cracking in the plant shield building at Davis-Besse.
Adverse legal decisions and outcomes related to Met-Ed's and Penelec's ability to recover certain transmission costs through their transmission service charge riders.
The continuing availability of generating units and changes in their ability to long term forecast reporting requirements. Applicationsoperate at or near full capacity.
Replacement power costs being higher than anticipated or inadequately hedged.
The ability to comply with applicable state and federal reliability standards and energy efficiency mandates.
Changes in customers' demand for rehearing filedpower, including but not limited to, changes resulting from the implementation of state and federal energy efficiency mandates.
The ability to accomplish or realize anticipated benefits from strategic goals.
FirstEnergy's ability to improve electric commodity margins and the impact of, among other factors, the increased cost of coal and coal transportation on such margins.
The ability to experience growth in mid-November 2009 were granted on December 9, 2009 for the sole purposedistribution business.
The changing market conditions that could affect the value of further considerationassets held in FirstEnergy's NDTs, pension trusts and other trust funds, and cause FirstEnergy and its subsidiaries to make additional contributions sooner, or in amounts that are larger than currently anticipated.
The impact of changes to material accounting policies.
The ability to access the public securities and other capital and credit markets in accordance with FirstEnergy's financing plan, the cost of such capital and overall condition of the matters raisedcapital and credit markets affecting FirstEnergy and its subsidiaries.
Changes in those applications.  general economic conditions affecting FirstEnergy and its subsidiaries.
Interest rates and any actions taken by credit rating agencies that could negatively affect FirstEnergy's and its subsidiaries' access to financing or their costs of financings and increase requirements to post additional collateral to support outstanding commodity positions, LOCs and other financial guarantees.
The PUCO has not yet issued a substantive Entrycontinuing uncertainty of the national and regional economy and its impact on Rehearing.  major industrial and commercial customers of FirstEnergy and its subsidiaries.
Issues concerning the soundness of financial institutions and counterparties with which FirstEnergy and its subsidiaries do business.
Issues arising from the completed merger of FirstEnergy and AE and the ongoing coordination of their combined operations


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including FirstEnergy's ability to maintain relationships with customers, employees or suppliers, as well as the ability to continue to successfully integrate the businesses and realize cost savings and any other synergies .
The rules implementing the requirements of SB221 went into effect on December 10, 2009. The Ohio Companies, on October 27, 2009, submitted an applicationrisks and other factors discussed from time to amend their 2009 statutory energy efficiency benchmarks to zero. As referenced above, on January 7, 2010, the PUCO issued an Order granting the Ohio Companies’ request to amend the energy efficiency benchmarks.time in FirstEnergy's and its applicable subsidiaries' SEC filings, and other similar factors.

Additionally under SB221, electric utilitiesDividends declared from time to time on FE's common stock during any annual period may in the aggregate vary from the indicated amount due to circumstances considered by FE's Board of Directors at the time of the actual declarations. A security rating is not a recommendation to buy or hold securities and electric service companiesis subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.
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 FirstEnergy's 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. The registrants expressly disclaim any current intention to update, except as required by law, any forward-looking statements contained herein as a result of new information, future events or otherwise.
See Item 1A. Risk Factors for additional information regarding risks that may impact our business, financial condition and results of operations.


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FIRSTENERGY CORP.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
Earnings available to FirstEnergy Corp. in 2011 were $885 million, or $2.22 per basic share of common stock ($2.21 diluted), compared with $742 million, or $2.44 per basic share of common stock ($2.42 diluted), in 2010 and $872 million, or $2.87 per basic share ($2.85 diluted), in 2009.
Change in Earnings Per Basic Share From Prior Year 2011 2010
     
Earnings Per Basic Share — Prior Year $2.44
 $2.87
Segment operating results(1)-
    
Regulated Distribution 0.05
 0.04
Competitive Energy Services (0.15) 0.10
Regulated Independent Transmission (0.06) 0.12
Non-core asset sales/impairments 0.67
 (0.37)
Generating plant impairments 0.08
 (0.78)
Trust securities impairments 0.02
 0.03
Litigation resolution (0.07) 0.01
Regulatory charges 0.03
 0.45
Mark-to-market adjustments-    
Pension and OPEB actuarial assumptions (0.47) 0.30
All other 0.02
 0.35
Organizational restructuring - 2009 —
 0.14
Debt redemption premiums (0.01) 0.32
Merger-related costs (0.29) (0.16)
Merger Accounting - commodity contracts (0.26) —
Net merger accretion(1)(2)(3)
 0.54
 —
Income tax resolution / retiree drug subsidy (0.03) (0.57)
Settlement of uncertain tax positions (0.05) (0.11)
Depreciation (0.09) (0.02)
Interest expense, net of amounts capitalized (0.14) 0.04
Investment income (0.03) (0.19)
Change in effective tax rate 0.04
 (0.17)
Other (0.02) 0.04
Earnings Per Basic Share $2.22
 $2.44
(1)Excludes amounts that are requiredshown separately
(2)Includes dilutive effect of shares issued in connection with the Allegheny merger
(3)Includes 10 months of Allegheny results in 2011

Merger
On February 25, 2011, the merger between FirstEnergy and AE closed. Pursuant to servethe terms of the Agreement and Plan of Merger between FirstEnergy, Merger Sub and AE, Merger Sub merged with and into AE with AE continuing as the surviving corporation and a wholly owned subsidiary of FirstEnergy. As part of their load from renewable energy resources equivalent to 0.25%the merger, AE shareholders received 0.667 of a share of FirstEnergy common stock for each AE share outstanding as of the KWH they serve in 2009.  merger completion date and all outstanding AE equity-based employee compensation awards were converted into FirstEnergy equity-based awards on the same basis.
In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RFPs sought renewable energy RECs, including solar 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 December 7, 2009, the Ohio Companies filed an applicationconnection with the PUCO seeking a force majeure determination regarding the Ohio Companies’ compliance with the 2009 solar energy resources benchmark,merger, FirstEnergy recorded merger transaction costs of approximately $91 million ($73 million net of tax and seeking a reduction$65 million ($47 million net of tax) during 2011 and 2010, respectively. These costs are included in “Other operating expenses” in the benchmark. The PUCO hasConsolidated Statements of Income. In addition, during 2011, $93 million of pre-tax merger integration costs and $36 million of pre-tax charges from merger settlements approved by regulatory agencies were recognized. Charges resulting from merger settlements are not yet ruledexpected to be material in future periods.
FirstEnergy exceeded its 2011 merger benefits target. During 2011, FirstEnergy completed savings initiatives that allowed the


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company to capture pre-tax annualized merger benefits of approximately $267 million compared to the annual target of $210 million.

Operational Matters

PJM RTO Integration

On June 1, 2011, ATSI successfully integrated into PJM. With this transition, all of FirstEnergy's generation, transmission and distribution facilities are now in PJM.

Transmission Expansion

On May 19, 2011, TrAIL's 500-kV transmission line, spanning more than 150 miles from southwestern Pennsylvania through West Virginia to northern Virginia, was completed and energized.

Nuclear Generation

On April 11, 2011, Beaver Valley Power Station Unit 2 returned to service following a March 7, 2011 shutdown for refueling and maintenance. During the outage, 60 of the 157 fuel assemblies were exchanged, safety inspections were conducted, and numerous maintenance and improvement projects were completed that we believe will result in continued safe and reliable operations.

On June 7, 2011, the Perry Nuclear Power Plant returned to service following a scheduled shutdown for refueling and maintenance which began on April 18, 2011. During the outage, 248 of the 748 fuel assemblies were replaced and safety inspections were successfully conducted. Additionally, numerous preventative maintenance activities and improvement projects were completed that application.we believe will result in continued safe and reliable operations, including replacement of several control rod blades, rewind of the generator, and routine work on more than 150 valves, pumps and motors.

On October 20, 2009,2, 2011, FENOC completed the Ohio Companies filedcontrolled shutdown of the Perry Plant due to the loss of a startup transformer. Subsequently, a spare replacement transformer from Davis-Besse Nuclear Power Station was transported to the Perry Plant for modification and installation. The new transformer was installed in 2011.

During 2011, FENOC broke ground for new Emergency Operations Facilities at all three of its nuclear sites. Each of the 12,000 square-foot facilities will house activities related to maintaining public health and safety during the unlikely event of an MRO to procure electric generation serviceemergency at the plant and allow for improved coordination between the period beginning Juneplant, state and local emergency management agencies.

On October 1, 2011. The proposed MRO would establish2011, the Davis-Besse Nuclear Power Station began a CBP to secure generation supplyscheduled outage for customers whoreplacement of its reactor vessel head and other scheduled maintenance. On October 10, 2011, following opening of the building for installation of the new reactor head, a sub-surface hairline crack was identified in one of the exterior architectural elements on the shield building. These elements serve as architectural features and do not shop with an alternative supplierhave structural significance. During investigation of the crack at the shield building opening, concrete samples and would beelectronic testing found similar sub-surface hairline cracks in all material respects,most of the building's architectural elements. FENOC's investigation also identified other indications of cracking. Included among them were sub-surface hairline cracks in the upper portion of the shield building (above 780 feet of elevation) and in the vicinity of the main steam line penetrations. A team of industry-recognized structural concrete experts and Davis-Besse engineers have determined these conditions do not affect the facility's structural integrity or safety. On February 27, 2012, FENOC sent a root cause evaluation report to the CBP conducted in May 2009 in that it would procure energy,NRC. On December 6, 2011, the Davis-Besse Nuclear Power Station returned to service. The new reactor vessel head features control rod nozzles made of an enhanced material and further promotes safe and reliable operation of the plant.

Coal and Gas Fired Generation

On July 28, 2011, FirstEnergy completed the sale of the Fremont Energy Center to American Municipal Power, Inc. for $510 million based on 685 MW of output. The purchase price can be incrementally increased, not to exceed an additional $16 million, to reflect additional transmission export capacity up to 707 MW.

On October 18, 2011, FirstEnergy sold its Richland (432 MW) 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 periodsStryker (18 MW) Peaking Facilities for generation supply designed to reduce potential volatility and supplier risk and encourage bidder participation. A technical conference was held on October 29, 2009. Hearings took place in December 2009 and the matter has been fully briefed. Pursuant to SB221, the PUCO has 90 daysapproximately $80 million. The proceeds from the datesale of the application to determine whether the MRO meets certain statutory requirements. Although the Ohio Companies requested a PUCO determination bythese non-core assets reduced FirstEnergy's net debt position.

On January 18, 2010, on February 3, 2010, the PUCO26, 2012, FirstEnergy announced that its determinationunregulated generation subsidiaries will retire six older coal-fired plants located in Ohio, Pennsylvania and Maryland. On February 8, 2012, FirstEnergy announced that MP will retire three older coal-fired plants located in West Virginia. All of these generating plants will be closed by September 1, 2012. The decision to close the plants is the result of a comprehensive review of FirstEnergy's coal-fired generating facilities in light of the MATS rules that were recently finalized and other environmental regulations. These closures are subject to review for reliability impacts by PJM. In addition, MP will make a filing with the WVPSC to provide them with information regarding the retirement of its plants. As a result of this decision, impairment charges associated with these assets were recognized by FirstEnergy, aggregating approximately $334 million ($207 million after-tax) in the fourth quarter of 2011, including approximately $243 million ($152 million after-tax) which is applicable to FES. See Note 11, Impairment of Long-lived Assets, for further information on the retirement of these plants.



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The total capacity of the competitive plants that will be retired is approximately 2,700 MW and the total capacity of the three regulated plants that will be retired is approximately 660 MW. Recently, these plants served mostly as peaking or intermediate facilities, generating, on average, approximately 10 percent of the electricity produced by FirstEnergy's generation subsidiaries over the past three years.

On February 24, 2012, PJM notified FirstEnergy of its preliminary analysis of the reliability impacts that may result from closure of the older competitive coal-fired generating units. PJM's preliminary analysis indicated that there would be delayed. Undersignificant reliability concerns that will need to be addressed. FirstEnergy intends to continue to actively engage in discussions with PJM regarding this notification, including the possible continued operation of certain plants.

Signal Peak

On October 18, 2011, FirstEnergy announced that Gunvor Group, Ltd. purchased a determinationone-third interest in Global Holding, a joint venture that owns the Signal Peak coal mine in Montana and the related Global Rail coal transportation operations. The sale strengthened FirstEnergy's balance sheet in the following ways:

Proceeds of $257.5 million reduced FirstEnergy's net debt position;
De-consolidation of Signal Peak resulted in the reduction of indebtedness by $360 million and an increase to equity of $50 million on FirstEnergy's Consolidated Balance Sheet; and
The gain on sale and revaluation of FirstEnergy's remaining ownership stake increased equity by an additional $370 million.

Following the sale, FirstEnergy, through its wholly owned subsidiary, FEV, has a one-third interest in Global Holding. FGCO has a long-term coal supply agreement with Signal Peak for up to 10 million tons per year. FGCO has re-evaluated its coal usage under that agreement and has determined to resell its coal purchased from Signal Peak to an affiliate of Global Holding; provided, however, that such statutory requirements are met,affiliate may require FGCO to repurchase up to 2 million tons annually from the Ohio Companies would be ableexisting underground mines, and, if Signal Peak develops surface mines, it could require FGCO to implement the MROpurchase an additional 2 million tons per year. FirstEnergy remains a 100% guarantor on Signal Peak's and conduct the CBP.Global Rail's $350 million senior secured credit facility. See Guarantees and Other Assurances below.

FirstEnergy Utilities Respond to Unprecedented Storms

In late August 2011, FirstEnergy experienced unprecedented damage in its service territory as a result of Hurricane Irene. Approximately 1.1 million customers were affected by outages in areas served by JCP&L, Met-Ed, Penelec and PE. Approximately 5,000 FirstEnergy employees and 2,800 contractors, including utility line workers from other utilities, assisted with the restoration work. The cost of the storm totaled approximately $89 million, of which $4 million reduced pre-tax income in 2011 and $85 million was capitalized or deferred for future recovery from customers.

On October 29, 2011, FirstEnergy was affected by a snowstorm that paralyzed much of the East Coast, including our eastern service areas. Approximately 820,000 customers of JCP&L, Met-Ed, PE, MP, Penelec and WP were affected by the storm that brought down more than 800 poles and approximately 10,000 spans of wire. More than 9,600 employees, contractors and other utilities' crews helped in the restoration. The pre-tax total cost of the storm was approximately $125 million, of which $6 million reduced pre-tax income in 2011 and $119 million was capitalized or deferred for future recovery from customers.

Financial Matters
During 2011, FirstEnergy redeemed or repurchased approximately $520.4 million principal amount of PCRBs, as summarized in the following table. Approximately $28.5 million of FGCO FMBs and $98.9 million of NGC FMBs associated with the PCRBs were returned for cancellation by the associated LOC providers.
SubsidiariesAmount 
 (In millions) 
AE Supply$53.0
(1) 
FGCO$198.2
(2) 
NGC$213.5
(2) 
MP$70.2
(1) 
(1)
Includes $14.4 million of PCRBs redeemed for which MP and AE Supply are co-obligors.
(2)
Subject to market conditions, these PCRBs are being held for future remarketing.

On May 4, 2011, AE terminated its $250 million credit facility due to other available funding sources following completion of the merger with FirstEnergy.

On June 17, 2011, FirstEnergy and certain of its subsidiaries entered into two 5-year revolving credit facilities with a total borrowing capacity of $4.5 billion. These facilities consist of a $2 billion revolving credit facility for FirstEnergy and its regulated utility subsidiaries


49


and a $2.5 billion revolving credit facility for FES and AE Supply. Prior separate facilities ($2.75 billion at FirstEnergy, $1 billion at AE Supply, $110 million at MP, $150 million at PE and $200 million at WP) were terminated.

During the third quarter of 2011, FirstEnergy received approximately $130 million from assigning a substantially below-market, long-term fossil fuel contract to a third party. As a result, FirstEnergy entered into a new long-term contract with another supplier for replacement fuel based on current market prices. The new contract runs for nine years, which is the remaining term of the assigned contract. The transaction reduced fuel costs during the quarter by approximately $123 million.

TrAIL's primary investment, the Trans-Allegheny Interstate Line (a 500-kV transmission project that extends from Southwestern Pennsylvania through West Virginia to Northern Virginia), was completed in May 2011.

On January 26, 2012, FirstEnergy announced a change to its method for accounting for pensions and OPEB effective in 2011 (see Note 1, Organization, Basis of Presentation and Significant Accounting Policies of the Combined Notes to the Consolidated Financial Statements). We also disclosed that we made a $600 million voluntary contribution to our pension plan earlier that month.

Regulatory Matters

Met-Ed and Penelec purchase a portionTransition to Competitive Markets

The Pennsylvania Companies began the move to competitive markets with the expiration of their PLRthe rate caps on Met-Ed's and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement allowsPenelec's retail generation rates on December 31, 2010. Beginning in 2011, Met-Ed and Penelec to sellobtained their power supply from the output of NUG energy to thecompetitive wholesale market and requires FESfully recover their generation costs through retail rates. The Ohio Companies, Penn, WP and JCP&L previously transitioned to provide energy at fixed prices to replace any NUG energy sold tocompetitive generation markets.

Marginal transmission loss recovery

On March 3, 2010, the extent needed forPPUC issued an order denying Met-Ed and Penelec the ability to satisfy their PLR and default service obligations.

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 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 proposed a staggered procurement schedule, which varies by customer class,recover marginal transmission losses through the use of a descending clock auction. On August 12, 2009,transmission service charge riders in their respective tariffs which applies to the periods including June 1, 2008 through December 31, 2010. Subsequently, Met-Ed and Penelec filed a settlement agreementPetition for Review 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 proposes a staggered procurement schedule, which varies by customer class. On September 2, 2009, the ALJ issued a Recommended Decision (RD) approving the settlement and adopted the Met-Ed and Penelec’s positions on two reserved issues. On November 6, 2009, the PPUC entered an Order approving the settlement and finding in favor of Met-Ed and Penelec on the two reserved issues.  Generation procurement began in January 2010.

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On May 22, 2008, the PPUC approved 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 intervenors 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.  On January 28, 2010, the PPUC adopted a motion which denies the recovery of marginal transmission losses through the TSC for the period of June 1, 2007 through March 31, 2008, and instructs Met-Ed and Penelec to work with the parties and file a petition to retain any over-collection, with interest, until 2011 for the purpose of providing mitigation of future rate increases starting in 2011 for their customers.  Met-Ed and Penelec are now awaiting an order, which is expected to be consistent with the motion. If so, Met-Ed and Penelec plan to appeal such a decision to the Commonwealth Court of Pennsylvania. AlthoughPennsylvania (Commonwealth Court) appealing the ultimate outcomePPUC's order. On June 14, 2011, the Commonwealth Court affirmed the PPUC's decision that marginal transmission losses are not recoverable as transmission costs. On July 13, 2011, Met-Ed and Penelec filed a federal complaint with the United States District Court for the Eastern District of this matter cannot be determined at this time, itPennsylvania and on the following day, filed a Petition for Allowance of Appeal to the Pennsylvania Supreme Court. Met-Ed and Penelec believe the Commonwealth Court's decision contradicts federal law and is the belief of the companies that they should prevail in any such appealinconsistent with prior PPUC and court decisions and therefore expect to fully recover the approximately $170.5 millionrelated regulatory assets ($138.7189 million for Met-Ed and $31.8$65 million for Penelec) in marginal transmission losses. In January 2011 and continuing for 29 months, pursuant to a related PPUC order, Met-Ed and Penelec began crediting customers for the period prior to January 1, 2011.amounts at issue pending the outcome of court appeals.

Ohio Energy Efficiency and Peak Demand Reduction Portfolio Plan

On May 28, 2009,March 23, 2011, the PPUCPUCO approved Met-Ed’sthe three-year Energy Efficiency and Penelec’s annual updates to their TSC riderDemand Reduction portfolio plan for the period June 1, 2009 through May 31, 2010 subjectOhio Companies. The Ohio Companies' plan was developed to comply with the Energy Efficiency mandate in Ohio's SB 221, passed in 2008. This law requires that utilities in Ohio reduce energy usage by 22.2 percent by 2025 and peak demand by 7.75 percent by 2018, develop a portfolio plan, and meet annual benchmarks to measure progress.

NYSEG Ruling

On July 11, 2011, FirstEnergy was found to be a potentially responsible party under CERCLA indirectly liable for a portion of past and future clean-up costs at certain legacy MGP sites in New York. As a result, FirstEnergy recognized additional expense of $29 million during the second quarter of 2011.

West Virginia Fuel, Purchased Power Cost Decision

On December 30, 2011, MP and PE announced that the WVPSC issued an order regarding the companies' adjustment of fuel and purchased power costs. The WVPSC's order approved a settlement agreement between the companies, the Consumer Advocate Division, the Staff of the WVPSC and the West Virginia Energy Users Group. In the approved settlement, parties have agreed that the companies will recover an additional $19.6 million in 2012, an approximate 1.7 percent increase, primarily reflecting rising coal prices over the past two years, with certain additional amounts to be recovered over time with a carrying charge.
FIRSTENERGY’S BUSINESS
With the completion of the AE merger in the first quarter of 2011, FirstEnergy reorganized its management structure, which resulted in changes to its operating segments to be consistent with the manner in which management views the business. The new structure supports the combined company's primary operations - distribution, transmission, generation and the marketing and sale of its products. The external segment reporting is consistent with the internal financial reporting used by FirstEnergy's chief executive


50


officer (its chief operating decision maker) to regularly assess the performance of the business and allocate resources. FirstEnergy now has three reportable operating segments - Regulated Distribution, Regulated Independent Transmission and Competitive Energy Services.
Prior to the outcomechange in composition of business segments, FirstEnergy's business was comprised of two reportable operating segments. The Energy Delivery Services segment was comprised of FirstEnergy's then eight existing utility operating companies that transmit and distribute electricity to customers and purchase power to serve their POLR and default service requirements. The Competitive Energy Services segment was comprised of FES, which supplies electric power to end-use customers through retail and wholesale arrangements. The “Other/Corporate” amounts consisted of corporate items and other businesses that were below the quantifiable threshold for separate disclosure. Disclosures for FirstEnergy's operating segments for 2010 have been reclassified to conform to the revised presentation.
The changes in FirstEnergy's reportable segments during 2011 consisted primarily of the proceedingfollowing:
Energy Delivery Services was renamed Regulated Distribution and the operations of MP, PE and WP, which were acquired as part of the merger with AE, and certain regulatory asset recovery mechanisms formerly included in the “Other/Corporate” segment, were placed into this segment.
A new Regulated Independent Transmission segment was created consisting of ATSI, and the operations of TrAIL and FirstEnergy's interest in PATH; TrAIL and PATH were acquired as part of the merger with AE. The transmission assets and operations of JCP&L, Met-Ed, Penelec, MP, PE and WP remained within the Regulated Distribution segment.
AE Supply, an operator of generation facilities that was acquired as part of the merger with AE, was placed into the Competitive Energy Services segment with FES.

Regulated Distribution distributes electricity through our ten utility distribution companies, serving approximately 6 million customers within 67,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also includes the transmission operations of JCP&L, Met-Ed, Penelec, WP, MP and PE and the regulated electric generation facilities in West Virginia and New Jersey which MP and JCP&L, respectively, own or contractually control. Its results reflect the commodity costs of securing electric generation and the deferral and amortization of certain fuel costs.
The service areas of our regulated distribution utilities are summarized below:
CompanyArea ServedCustomers Served
OECentral and Northeastern Ohio1,032,000
PennWestern Pennsylvania161,000
CEINortheastern Ohio747,000
TENorthwestern Ohio309,000
JCP&LNorthern, Western and East Central New Jersey1,099,000
Met-EdEastern Pennsylvania553,000
PenelecWestern Pennsylvania590,000
WPSouthwest, South Central and Northern Pennsylvania718,000
MPNorthern, Central and Southeastern West Virginia387,000
PEWestern Maryland and Eastern West Virginia390,000
5,986,000

Regulated Independent Transmission transmits electricity through transmission lines and its revenues are primarily derived from a formulaic rate that recovers costs and a return on investment for capital expenditures in connection with TrAIL, PATH and other projects, revenues from providing transmission services to electric energy providers and power marketers, and revenues from operating a portion of the FirstEnergy transmission system. Its results reflect the net transmission expenses related to the 2008 TSC filingdelivery of the respective generation loads.

Competitive Energy Services supplies, through FES and AE Supply, electric power to end-use customers through retail and wholesale arrangements, including competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland and the provision of partial POLR and default service for some utilities in Ohio, Pennsylvania and Maryland, including but not limited to the Utilities. This segment controls approximately 17,000 MWs of capacity (excluding approximately 2,700 MWs from unregulated plants expected to be closed by September 1, 2012) (see Note 11, Impairment of Long-Lived Assets of the Combined Notes to the Consolidated Financial Statements) and also purchases electricity to meet sales obligations. The segment's net income is primarily derived from electric generation sales less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO (prior to June 1, 2011)


51


to deliver energy to the segment's customers.
Other/Corporate contains corporate items and other businesses that are below the quantifiable threshold for separate disclosure as a reportable segment. (See Note 19, Segment Information of the Combined Notes to the Consolidated Financial Statements for further information on FirstEnergy's reportable operating segments.)
STRATEGY AND OUTLOOK

FirstEnergy's vision is to be a leading regional energy provider, recognized for operational excellence, outstanding customer service and our commitment to safety; the choice for long-term growth, investment value and financial strength; and a company driven by the leadership, skills, diversity and character of our employees.

FirstEnergy has grown over the last 15 years through several strategic mergers and asset transactions. Our most recent merger with Allegheny was completed in February 2011, significantly increasing our customer base and generating capacity and accelerating our movement further into eastern competitive markets. Also during 2011, we completed the transition to competitive markets in Pennsylvania and moved our ATSI assets into PJM, so that we now operate within a single regional transmission system.

FirstEnergy is uniquely positioned as the nation's largest contiguous electric system, with complementary assets across our generation, transmission and distribution delivery operations. These assets are in a prime location of PJM's competitive markets.

Our substantial regulated operations include 10 distribution utilities serving a balanced base of nearly 6 million customers across 5 states. We are also one of the largest owners of transmission assets in PJM with nearly 20,000 miles of high-voltage lines, including two independent transmission companies with significant assets. Combined, our utilities and transmission operations provide financial stability with strong cash flow and dividend support to FirstEnergy.

Our market-focused business model integrates more than 17,000 MWs of competitive generation, excluding approximately 2,700 MWs from unregulated plants expected to be closed by September 1, 2012, and are subject to review by PJM for reliability impacts(see Note 16, Commitment, Guarantees and Contingencies, regarding PJM's review of the our plans), with a multi-channel retail sales platform, providing a higher value for every MWH we generate. We primarily target customers in competitive markets close to our generation assets.

We believe we are well-positioned for upcoming environmental changes due to the considerable investments we have made in recent years to diversify our generation fleet and improve its environmental performance. As a result of the MATS rules recently finalized by the EPA, and other previously announced environmental regulations, FirstEnergy announced in early 2012 its intent to retire nine older coal-fired power plants, totaling 3,349 MW, located in Ohio, Pennsylvania, Maryland and West Virginia by September 1, 2012. When the retired fossil plants are removed from our fleet, nearly 100% percent of our generation output will be from either low or non-emitting facilities, including nuclear, hydro, natural gas and scrubbed coal units. This further positions our fleet to deliver superior value in the future.

We continue to face challenges related to macro-economic factors. These include slow economic recovery across portions of our service territory, which affect our distribution deliveries volumes to residential, commercial and industrial customers, and depressed natural gas and wholesale electricity prices, which affect revenues from our competitive retail business and generation fleet. However, we believe we are one of the better positioned companies in our industry to benefit from eventual increases in energy and capacity prices as economic conditions improve.

Financial Outlook

We intend to manage our operating and capital costs in order to achieve our financial goals and commitment to shareholders.

Our liquidity position remains strong, with approximately $49 million of short-term cash investments and over $4.3 billion of available liquidity as of January 31, 2012.

Positive earnings drivers for 2012 are expected to include:

▪A full year contribution from the Allegheny merger;

▪Higher competitive retail revenues as a result of continued growth in the business;

▪Lower fuel and operation and maintenance expenses due to the retirement of certain coal-fired plants in 2012 and from a continued focus on controlling our costs; and

▪Reduced interest expense as a result of debt redemptions during 2011.

Negative earnings drivers for 2012 are expected to include:

▪Lower margins for our competitive energy service business from depressed market prices of power and lower capacity


52


prices resulting from the PJM RPM auction beginning June 1, 2012;

▪Higher gross receipts taxes associated with increased competitive retail sales in Pennsylvania; and

▪Increased depreciation expenses from capital projects that were placed in service during 2011.

On January 5, 2012, we made a $600 million voluntary contribution to our pension plan bringing its funding level to 90% on an accumulated benefit obligation basis.

Capital Expenditures Outlook

Our capital expenditures in 2012 are estimated to be $2.1 billion (excluding nuclear fuel), a decrease of approximately $393 million from 2011. In addition to internal sources to fund capital requirements for 2012 and beyond, FirstEnergy expects to rely on external sources of funds.

Capital expenditures for our Regulated Distribution segment are forecast to decrease by $63 million in 2012 from $1.1 billion in 2011. The expected decrease primarily reflects the absence of storm restoration costs related to Hurricane Irene and the October 2011 snowstorm. For our Regulated Independent Transmission segment, capital expenditures are expected to decrease to $105 million in 2012 from $190 million in 2011. The decrease reflects the completion of TrAIL's 500-kV transmission line in 2011.

Expenditures for Ohio and Pennsylvania energy efficiency and advanced metering initiatives are expected to be primarily recovered from distribution customers and federal stimulus funding. Other capital investments in our transmission and distribution infrastructure are planned to satisfy transmission capacity and reliability requirements, connect new load delivery and wholesale generation points, and achieve cost-effective improvements in the reliability of our service.

For our Competitive Energy Services segment, capital expenditures are expected to increase by $32 million to $803 million in 2012. The main drivers of the increase include steam generator replacement projects at Davis-Besse and Beaver Valley Unit 2 and turbine rotor replacement projects at Perry and Beaver Valley Unit 2. Other planned generation investments provide for maintenance of critical generation assets, delivering operational improvements to enhance reliability, supporting environmental compliance, and advancing our generation to market strategy.

For 2013, we anticipate baseline capital expenditures of approximately $2.0 billion, which exclude any potential additional strategic opportunities, future mandated spending, energy efficiency or environmental spending relating to MATS. Planned capital initiatives are intended to promote reliability, improve operations, and support current environmental and energy efficiency directives.

Environmental Outlook

We continually strive to enhance environmental protection and remain good stewards of our natural resources. We devote significant resources to environmental compliance efforts, and our employees share a commitment to, and accountability for, environmental performance. Our corporate focus on continuous improvement is integral to our environmental programs.

We have spent more than $10 billion on environmental protection efforts since the initial passage of the Clean Air and Water Acts in the 1970s, and these investments demonstrate our continuing commitment to the environment. Recent investments of $3.0 billion at our Hatfield, Fort Martin and Sammis Plants, further reduced emissions of SO2 by over 95%, and NOx by at least 64% at these facilities. Since 1990, we have reduced emissions of NOx by more than 76%, SO2 by more than 86%, and mercury by approximately 56%.

We have taken aggressive steps over the past two decades that have increased our generating capacity without adding to overall CO2 emissions. For example, since 1990, we have reconfigured our fleet by retiring 1,312 MWs and committing to retire in the near future 3,349 MWs of older, coal-based generation and adding more than 1,800 MWs of non-emitting capacity. Through these and other actions, we have increased our generating capacity by nearly 15% over the same period while avoiding over 370 million metric tons of CO2 emissions.

We have taken a leadership role in pursuing new ventures to test and develop new technologies that may achieve additional reductions in CO2 emissions. These include:

Sales of over 1 million MWH per year of wind generation.

CO2 sequestration testing to gain a better understanding of the potential for geological storage of CO2.

Supporting afforestation - growing forests on non-forested land - and other efforts designed to remove CO2 from the environment.

Reducing emissions of SF6 (sulfur hexafluoride) by nearly 15 metric tons, resulting in an equivalent reduction of nearly 315,000 metric tons of CO2, through the EPA's SF6 Emissions Reduction Partnership for Electric Power Systems.



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Supporting research to develop and evaluate cost effective sorbent materials for CO2 capture including work by EPRI and The University of Akron.

We remain actively engaged in the federal and state debate over future environmental requirements and legislation. We actively work with policy makers and regulators to develop fair and reasonable requirements, with the goal of reducing emissions while minimizing the economic impact on our customers. Due to the significant uncertainty as to the final form or timing of a significant number of regulations and legislation at both the federal and state levels, we are unable to determine the potential impact and risks associated with all future environmental requirements. The CSAPR was stayed at the end of 2011 and the federal appeals court reviewing CSAPR has scheduled an April 13, 2012 hearing. The new MATS were finalized at the end of 2011, which resulted in our decision to retire nine older coal-fired generation plants by September 1, 2012. Our current estimate is that it may cost approximately $1.3 - $1.7 billion to bring our remaining units into compliance.

We also have a long history of supporting research in distributed energy resources. Distributed energy resources include fuel cells, solar and wind systems or energy storage technologies located close to the customer or direct control of customer loads to provide alternatives or enhancements to the traditional electric power system. We are testing the world's largest utility-scale fuel cell system to determine its feasibility for augmenting generating capacity during summer peak-use periods. Through a partnership with EPRI, the Cuyahoga Valley National Park, the Department of Defense and Case Western Reserve University, two solid-oxide fuel cells were installed as part of a test program to explore the technology and the environmental benefits of distributed generation.

We are also evaluating the impact of distributed energy storage on the distribution system through analysis and field demonstrations of advanced battery technologies. FirstEnergy's EasyGreen® load-management program utilizes two-way communication capability with customers' non-critical equipment, such as air conditioners in New Jersey and Pennsylvania, to help manage peak loading on the electric distribution system. We have also made an online interactive energy efficiency tool, Home Energy Analyzer, available to our customers to help achieve electricity use reduction goals.
RISKS AND CHALLENGES
In executing our strategy, we face a number of industry and enterprise risks and challenges. See ITEM 1A. RISK FACTORS for a discussion of the risks and challenges faced by FirstEnergy and the Registrants.
RESULTS OF OPERATIONS
The financial results discussed below include revenues and expenses from transactions among FirstEnergy’s business segments. A reconciliation of segment financial results is provided in Note 19, Segment Information of the Combined Notes to the Consolidated Financial Statements. As described above,in Note 1, Organization, Basis of Presentation and Significant Accounting Policies, FirstEnergy elected to change its method of recognizing actuarial gains and losses for its defined benefit pension and OPEB plans and applied this change retrospectively to all periods presented. Earnings available to FirstEnergy by major business segment were as requiredfollows:
       Increase (Decrease)
 2011 2010 2009 2011 vs 2010 2010 vs 2009
 (In millions, except per share data)
Earnings By Business Segment:         
Regulated Distribution$570
 $553
 $335
 $17
 $218
Competitive Energy Services377
 210
 446
 167
 (236)
Regulated Independent Transmission112
 54
 39
 58
 15
Other and reconciling adjustments(1)
(174) (75) 52
 (99) (127)
Earnings available to FirstEnergy Corp.$885
 $742
 $872
 $143
 $(130)
          
Earnings Per Basic Share$2.22
 $2.44
 $2.87
 $(0.22) $(0.43)
          
Earnings Per Diluted Share$2.21
 $2.42
 $2.85
 $(0.21) $(0.43)
(1)
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 — 2011 Compared with 2010
Financial results for FirstEnergy’s major business segments in 2011 and 2010 were as follows:


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2011 Financial Results Regulated Distribution Competitive Energy Services Regulated Independent Transmission Other and Reconciling Adjustments FirstEnergy Consolidated
  (In millions)
Revenues:          
External          
Electric $9,544
 $5,573
 $—
 $—
 $15,117
Other 460
 363
 391
 (140) 1,074
Internal —
 1,237
 —
 (1,170) 67
Total Revenues 10,004
 7,173
 391
 (1,310) 16,258
           
Operating Expenses:          
Fuel 268
 2,049
 —
 —
 2,317
Purchased power 4,672
 1,491
 —
 (1,177) 4,986
Other operating expenses 1,662
 2,256
 68
 (77) 3,909
Pensions and OPEB mark-to-market adjustment 290
 215
 2
 —
 507
Provision for depreciation 620
 415
 60
 26
 1,121
Amortization of regulatory assets, net 323
 —
 6
 —
 329
General taxes 724
 200
 33
 21
 978
Impairment of long-lived assets 87
 315
 —
 11
 413
Total Operating Expenses 8,646
 6,941
 169
 (1,196) 14,560
           
Operating Income 1,358
 232
 222
 (114) 1,698
           
Other Income (Expense):          
Gain on partial sale of Signal Peak —
 569
 —
 —
 569
Investment income 110
 56
 —
 (52) 114
Interest expense (573) (298) (46) (91) (1,008)
Capitalized interest 10
 40
 2
 18
 70
Total Other Income (Expense) (453) 367
 (44) (125) (255)
           
Income Before Income Taxes 905
 599
 178
 (239) 1,443
Income taxes 335
 222
 66
 (49) 574
Net Income 570
 377
 112
 (190) 869
Loss attributable to noncontrolling interest —
 —
 —
 (16) (16)
Earnings available to FirstEnergy Corp. $570
 $377
 $112
 $(174) $885


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2010 Financial Results Regulated Distribution Competitive Energy Services Regulated Independent Transmission Other and Reconciling Adjustments FirstEnergy Consolidated
  (In millions)
Revenues:          
External          
Electric $9,271
 $3,252
 $—
 $—
 $12,523
Other 300
 323
 242
 (123) 742
Internal 139
 2,301
 —
 (2,366) 74
Total Revenues 9,710
 5,876
 242
 (2,489) 13,339
           
Operating Expenses:          
Fuel —
 1,432
 —
 —
 1,432
Purchased power 5,273
 1,724
 —
 (2,373) 4,624
Other operating expenses 1,320
 1,393
 61
 (78) 2,696
Pensions and OPEB mark-to-market adjustment 82
 107
 (2) 3
 190
Provision for depreciation 433
 284
 37
 14
 768
Amortization of regulatory assets, net 712
 —
 10
 —
 722
General taxes 605
 124
 30
 17
 776
Impairment of long-lived assets —
 388
 —
 —
 388
Total Operating Expenses 8,425
 5,452
 136
 (2,417) 11,596
           
Operating Income 1,285
 424
 106
 (72) 1,743
           
Other Income (Expense):          
Investment income 102
 51
 —
 (36) 117
Interest expense (500) (232) (22) (91) (845)
Capitalized interest 4
 95
 2
 64
 165
Total Other Expense (394) (86) (20) (63) (563)
           
Income Before Income Taxes 891
 338
 86
 (135) 1,180
Income taxes 338
 128
 32
 (36) 462
Net Income 553
 210
 54
 (99) 718
Loss attributable to noncontrolling interest —
 —
 —
 (24) (24)
Earnings available to FirstEnergy Corp. $553
 $210
 $54
 $(75) $742



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Changes Between 2011 and 2010 Financial Results
Increase (Decrease)
 Regulated Distribution Competitive Energy Services Regulated Independent Transmission Other and Reconciling Adjustments FirstEnergy Consolidated
  (In millions)
Revenues:          
External          
Electric $273
 $2,321
 $—
 $—
 $2,594
Other 160
 40
 149
 (17) 332
Internal (139) (1,064) —
 1,196
 (7)
Total Revenues 294
 1,297
 149
 1,179
 2,919
           
Operating Expenses:          
Fuel 268
 617
 —
 —
 885
Purchased power (601) (233) —
 1,196
 362
Other operating expenses 342
 863
 7
 1
 1,213
Pensions and OPEB mark-to-market adjustment 208
 108
 4
 (3) 317
Provision for depreciation 187
 131
 23
 12
 353
Amortization of regulatory assets, net (389) —
 (4) —
 (393)
General taxes 119
 76
 3
 4
 202
Impairment of long-lived assets 87
 (73) —
 11
 25
Total Operating Expenses 221
 1,489
 33
 1,221
 2,964
           
Operating Income 73
 (192) 116
 (42) (45)
           
Other Income (Expense):          
Gain on partial sale of Signal Peak —
 569
 —
 —
 569
Investment income 8
 5
 —
 (16) (3)
Interest expense (73) (66) (24) —
 (163)
Capitalized interest 6
 (55) —
 (46) (95)
Total Other Income (Expense) (59) 453
 (24) (62) 308
           
Income Before Income Taxes 14
 261
 92
 (104) 263
Income taxes (3) 94
 34
 (13) 112
Net Income 17
 167
 58
 (91) 151
Loss attributable to noncontrolling interest —
 —
 —
 8
 8
Earnings available to FirstEnergy Corp. $17
 $167
 $58
 $(99) $143
Regulated Distribution — 2011 Compared with 2010
Net income increased by $17 million in 2011 compared to 2010, primarily due to earnings from the Allegheny companies and the absence of a 2010 regulatory asset impairment associated with the Ohio companies' ESP, partially offset by higher pensions and OPEB mark-to-market adjustment charges and merger-related costs. Lower generation revenues were offset with lower purchased power expenses.


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Revenues —
The increase in total revenues resulted from the following sources:
  For the year ended December 31  
Revenues by Type of Service 2011 2010 
Increase
(Decrease)
  (In millions)
Pre-merger companies:      
Distribution services $3,426
 $3,629
 $(203)
Generation:      
Retail 3,266
 4,457
 (1,191)
Wholesale 377
 702
 (325)
Total generation sales 3,643

5,159
 (1,516)
Transmission 262
 596
 (334)
Other 187
 326
 (139)
Total pre-merger companies 7,518
 9,710
 (2,192)
Allegheny companies 2,486
 —
 2,486
Total Revenues $10,004
 $9,710
 $294

The decrease in distribution service revenues for the pre-merger companies (FirstEnergy as it was organized prior to the February 2011 merger with Allegheny) primarily reflects lower transition revenues due to the completion of transition cost recovery by CEI in December 2010, an NJBPU-approved rate adjustment that became effective March 1, 2011, for all JCP&L customer classes, and the mid-year suspension of the Ohio Companies' recovery of deferred distribution costs. Partially offsetting the decreased distribution service revenues were increased rates in Met-Ed's and Penelec's transition riders and energy efficiency riders for the Pennsylvania and Ohio Companies. Distribution deliveries (excluding the Allegheny companies) increased by 0.1% in 2011 from 2010.The change in distribution deliveries by customer class is summarized in the following table:
  For the year ended December 31  
Electric Distribution MWH Deliveries 2011 2010 
Increase
(Decrease)
     
Pre-merger companies:      
Residential 39,369
 39,820
 (1.1)%
Commercial 32,610
 33,096
 (1.5)%
Industrial 35,637
 34,613
 3.0 %
Other 513
 522
 (1.7)%
Total pre-merger companies 108,129
 108,051
 0.1 %
Allegheny companies 33,449
    
Total Electric Distribution MWH Deliveries 141,578
 108,051
 31.0 %

Lower deliveries to residential and commercial customers primarily reflected decreased weather-related usage resulting from lower heating degree days (4%) and cooling degree days (7%) in 2011 compared to 2010. In the industrial sector, MWH deliveries increased to steel and electrical equipment customers by 10% and 12%, respectively, partially offset by decreased deliveries to automotive customers of 2% in 2011 compared to 2010.


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The following table summarizes the price and volume factors contributing to the $1,516 million decrease in generation revenues for the pre-merger companies in 2011 compared to 2010:
Source of Change in Generation Revenues 
Increase
(Decrease)
  (In millions)
Retail:  
Effect of decrease in sales volumes $(1,638)
Change in prices 447
  (1,191)
Wholesale:  
Effect of decrease in sales volumes (104)
Change in prices (221)
  (325)
Net Decrease in Generation Revenues $(1,516)

The decrease in retail generation sales volume was primarily due to increased customer shopping in the service territories of the pre-merger companies in 2011 compared to 2010. Total generation provided by alternative suppliers as a percentage of total MWH deliveries increased to 76% from 62% for the Ohio Companies, and to 52% from 10% in Met-Ed’s, Penelec’s and Penn's service territories. The increase in retail prices is the result of higher generation charges in Pennsylvania due to the removal of generation rate caps for Met-Ed and Penelec beginning on January 1, 2011, and the inclusion of transmission as part of the price of generation. Those impacts were partially offset by a decrease in the Ohio Companies' generation rates beginning in June 2011 with the removal of certain transmission charges in connection with the PPUC’sintegration into PJM.
The decrease in wholesale generation revenues reflected lower RPM revenues for Met-Ed and Penelec in the PJM market.
Transmission revenues decreased $334million primarily due to the termination of Met-Ed’s and Penelec’s TSC rates effective January 2007 rate order. For1, 2011. This is partially offset by a new rider that became effective for the Ohio Companies in June 2011 that recovers network integration transmission service charges.
Other revenues decreased by $139 million primarily due to the termination of Met-Ed's and Penelec's PSA with FES as of December 31, 2010, resulting in decreased capacity revenues.
The Allegheny companies added $2,486 million to revenues in 2011, including $571 million for distribution services, $1,661million from generation sales, $212 million of transmission revenues and $42 million of other revenues.
Operating Expenses —
Total operating expenses increased by $221 million in 2011. Excluding the Allegheny companies, total operating expenses decreased $1.9 billion due to the following:

Purchased power costs were $1.7 billion lower in 2011 due primarily to a decrease in volumes required. Decreased power purchased from FES primarily reflected the increase in customer shopping described above, the termination of Met-Ed’s and Penelec’s customersPSA with FES at the new TSCend of 2010, and less Ohio POLR load served by FES beginning in June 2011. The increase in volumes purchased from non-affiliates in 2011 is primarily due to Met-Ed’s and Penelec’s generation procurement plan effective January 1, 2011 and more Ohio POLR load served by non-affiliates, partially offset by a decrease in RPM expenses in the PJM market.


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Source of Change in Purchased Power 
Increase
(Decrease)
  (In millions)
Pre-merger companies:  
Purchases from non-affiliates:  
Change due to decreased unit costs $(826)
Change due to increased volumes 515
  (311)
Purchases from FES:  
Change due to increased unit costs 165
Change due to decreased volumes (1,601)
  (1,436)
   
Total pre-merger companies (1,747)
Purchases by Allegheny companies 1,146
Net Decrease in Purchased Power Costs $(601)
Other operating expenses decreased $37 million, primarily due to the following:
◦Storm restoration maintenance and removal expenses increased $126 million primarily related to restoration associated with Hurricane Irene and an October 2011 East Coast snowstorm, primarily impacting the JCP&L and Met-Ed service territories. Approximately $120 million of the total costs were deferred for future recovery from customers.
◦Energy efficiency program costs, which are also recovered through rates, increased by $92 million.
◦
A provision for excess and obsolete material of $13 million was recognized in 2011 due to revised inventory practices adopted in conjunction with the Allegheny merger.
◦The absence of a $7 million favorable JCP&L labor settlement that occurred in 2010.
◦Transmission expenses decreased $285 million primarily due to reduced congestion costs for Met-Ed and Penelec in 2011.
Pensions and OPEB mark-to-market adjustment charges increased $132 million as a result of higher net actuarial losses.
Depreciation expense increased $24 million primarily due to property additions since 2010.
Net amortization of regulatory assets decreased $368 million primarily due to reduced net PJM transmission and transition cost recovery, the absence of a $35 million regulatory asset impairment recognized in 2010 associated with the filing of the Ohio Companies' ESP on March 23, 2010, and the deferral of recoverable costs from Hurricane Irene and the 2011 East Coast snowstorm, partially offset by increased energy efficiency cost recovery.
General Taxes increased $10 million due to the absence of a favorable property tax settlement recognized in 2010.
Impairments of long-lived assets totaling $87 million in 2011 resulted from the pending shutdown of three coal-fired plants in West Virginia.


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The acquisition of the Allegheny companies resulted in an approximate 1%the inclusion of the following operating expenses in 2011:
Operating Expenses - Allegheny In Millions
   
Purchased power $1,146
Fuel 268
Transmission 120
Amortization of regulatory assets, net (21)
Pensions and OPEB mark-to-market adjustment 76
Other operating expenses 259
General taxes 109
Depreciation expense 163
Total Operating Expenses $2,120
Other Expense —
Other expense increased $59 million in 2011 due to interest expense on debt of the Allegheny companies partially offset by higher investment income on OE's and TE's nuclear decommissioning trusts and increased capitalized interest.
Regulated Independent Transmission — 2011 Compared with 2010
Net income increased by $58 million in 2011 compared to 2010 due to earnings associated with TrAIL and PATH of $79 million, partially offset by decreased earnings for ATSI of $20 million.
Revenues —
Total revenues increased by $149 million principally due to revenues from TrAIL and PATH, which were acquired as part of the merger with Allegheny, partially offset by a decrease in monthly bills, reflecting projectedATSI revenues due to the transition from MISO to PJM and the completion of vegetation management cost recovery in May 2011.
Revenues by transmission costsasset owner are shown in the following table:
Revenues by Transmission Asset Owner 2011 2010 
Increase
(Decrease)
  (In millions)
ATSI $207
 $242
 $(35)
TrAIL 170
 —
 170
PATH 14
 —
 14
Total Revenues $391
 $242
 $149
Operating Expenses —
Total operating expenses increased by $33 million principally due to the addition of TrAIL and PATH in 2011.
Other Expense —
Other expense increased $24 million in 2011 due to additional interest expense associated with TrAIL.
Competitive Energy Services — 2011 Compared to 2010
Net income increased by $166 million in 2011 compared to 2010. The increase in net income was primarily due to a $569 million gain ($358 million net of tax) on the partial sale of FEV's interest in Signal Peak in 2011 and decreased impairments of long-lived assets. Partially offsetting this was a decrease in sales margins of $193 million, a $66 million increase in interest expense and a $55 million decrease in capitalized interest compared to 2010.
Revenues —
Total revenues increased $1.3 billion in 2011 compared to 2010, primarily due to an increase in direct and governmental aggregation sales and the inclusion of the Allegheny companies, partially offset by a decline in POLR and structured sales.


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The increase in reported segment revenues resulted from the following sources:
Revenues by Type of Service 2011 2010 Increase (Decrease)
  (In millions)
Direct and Governmental Aggregation $3,785
 $2,493
 $1,292
POLR and Structured Sales 944
 2,589
 (1,645)
Wholesale 457
 397
 60
Transmission 108
 77
 31
RECs 67
 74
 (7)
Sale of OVEC participation interest —
 85
 (85)
Other 173
 161
 12
Allegheny Companies 1,639
 —
 1,639
Total Revenues $7,173
 $5,876
 $1,297
       
Allegheny Companies      
Direct and Government Aggregation $84
   

POLR and Structured Sales 561
   

Wholesale 912
   

Transmission 88
   

Other (6)   

Total Revenues $1,639
 

 

MWH Sales by Type of Service 2011 2010 Increase (Decrease)
  (In thousands)
Direct 46,187
 28,499
 17,688
Government Aggregation 17,722
 12,796
 4,926
POLR and Structured Sales 15,340
 50,358
 (35,018)
Wholesale 2,916
 5,391
 (2,475)
Allegheny Companies 26,609
 —
 26,609
Total Sales 108,774
 97,044
 11,730
       
Allegheny Companies      
Direct 1,390
   

POLR 7,974
   

Structured Sales 1,492
   

Wholesale 15,753
   

Total Sales 26,609
 




The increase in direct and governmental aggregation revenues of $1.3 billion resulted from the acquisition of new residential, commercial and industrial customers, as well as a reconciliation for costs already incurred. The TSC for Met-Ed’s customers increasednew governmental aggregation contracts with communities in Ohio and Illinois that provide generation 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 $57.5approximately 1.8 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.

Act 129 became effective in 2008 and addresses 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 requires utilities to file with the PPUC an energy efficiency and peak load reduction 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. 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 Pennsylvania Companies filed revised EE&C Plans on September 21, 2009. In an October 28, 2009 Order, the PPUC approved in part, and rejected in part, the Pennsylvania Companies' filing. Following additional filings related to the plans, including modifications as required by the PPUC, the PPUC issued an order on January 28, 2010, approving, in part, and rejecting, in part the Pennsylvania Companies’ modified plans. The Pennsylvania Companies filed final plans and tariff revisions on February 5, 2010 consistent with the minor revisions required by the PPUC.  The PPUC must approve or reject the plans within 60 days.

Act 129 also required utilities to file by August 14, 2009 with the PPUC smart meter technology procurement and installation plan to provide for the installation of smart meter technology within 15 years. On August 14, 2009, Met-Ed, Penelec and Penn jointly filed a Smart Meter Technology Procurement and Installation Plan. Consistent with the PPUC’s rules, 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. A Technical Conference and evidentiary hearings were held in November 2009. Briefs were filed on December 11, 2009, and Reply Briefs were filed on December 31, 2009. An Initial Decision was issued by the presiding ALJ on January 28, 2010.  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.  Exceptions are due on February 17, 2010, and Reply Exceptions are due on March 1.  The Pennsylvania Companies expect the PPUC to act on the plans in early 2010.

91
Legislation addressing rate mitigation and the expiration of rate caps has been 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.

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 at the end of 2011 compared to prepayapproximately 1.5 million customers at the end of 2010. Increases in direct sales volume were partially offset by lower unit prices.
The decrease in POLR and structured sales revenues of $1.6 billion was due to lower sales volumes to Met-Ed, Penelec and the Ohio Companies, partially offset by increased sales to non-affiliates and higher unit prices to the Pennsylvania Companies. The decline in POLR sales reflects our focus on more profitable sales channels.
Wholesale revenues increased $60 million due to higher wholesale prices partially offset by decreased volumes. The lower sales volumes were the result of decreased short-term (net hourly positions) transactions in MISO, partially offset by increased short-term transactions in PJM. In addition, capacity revenues earned by units that moved to PJM from MISO were partially offset by losses on financially settled sales contracts.



62


The following tables summarize the price and volume factors contributing to changes in revenues from generation sales:
Source of Change in Direct and Governmental Aggregation Increase(Decrease)
  (In millions)
Direct Sales:  
Effect of increase in sales volumes $1,034
Change in prices (75)
  959
Governmental Aggregation:  
Effect of increase in sales volumes 319
Change in prices 14
  333
Net Increase in Direct and Government Aggregation Revenues $1,292
Source of Change in POLR and Structured Revenues 
Increase
(Decrease)
  (In millions)
Effect of decrease in sales volumes $(1,800)
Change in prices 155
  $(1,645)
   
Source of Change in Wholesale Revenues Increase(Decrease)
  (In millions)
Effect of decrease in sales volumes $(182)
Change in prices 242
  $60
Operating Expenses —
Total operating expenses increased $1.5 billion in 2011. Excluding the Allegheny companies, total operating expenses decreased $98 million compared to 2010, due to the following factors:
Fuel costs decreased $177 million in 2011 compared to 2010 primarily due to cash received from assigning a substantially below-market, long-term fossil contract to a third party. In connection with its merger integration initiatives and risk management strategy, FirstEnergy continues to evaluate opportunities with respect to its commodity contracts. As a result of the assignment, FirstEnergy entered into a new long-term contract with another supplier for replacement fuel based on current market prices. Excluding the assignment, fuel costs decreased $54 million in 2011 compared to 2010 due to decreased volumes consumed ($115 million), partially offset by higher unit prices ($61 million). The decrease in fossil fuel expense reflects lower generation needed to satisfy sales requirements. Lower fossil fuel expenses were partially offset by a $22 million increase in nuclear fuel costs, which rose principally due to higher nuclear fuel unit prices following the refueling outages that occurred in 2010 and 2011.
Purchased power costs decreased $382 million as lower volumes ($649 million) were partially offset by higher unit prices ($267 million). The decrease in volume primarily relates to the expiration at the end of 2010 of a 1,300 MW third party contract associated with serving Met-Ed and Penelec.
Fossil operating costs increased $36 million due primarily to higher labor, contractor and material costs resulting from an amountincrease in planned and unplanned outages, which were partially offset by reduced losses from the sale of excess coal.
Nuclear operating costs increased $53 million primarily due to Perry and Beaver Valley Unit 2 refueling outages in 2011. While Davis-Besse had a refueling outage in 2010 and an outage in 2011 to replace the reactor vessel head, the work performed on their monthly electric bills duringboth outages was largely capital-related.
Transmission expenses increased $249 million due primarily to higher congestion, network and line loss expenses.
Depreciation expense increased $20 million principally due to the completion of the Sammis projects at the end of 2010.
General taxes increased $36 million due to an increase in revenue-related taxes.


63


Impairments of long-lived assets decreased $85 million compared to last year. The 2011 charges are due to the pending shutdown of six unregulated, coal-fired generating units; charges in 2010 related to operational changes at certain smaller coal-fired units.
Other operating expenses increased $152 million primarily due to a $54 million provision for excess and obsolete material relating to revised inventory practices adopted in connection with the Allegheny merger; a $64 million increase in pensions and OPEB mark-to-market adjustment charges from higher net actuarial losses; a $10 million increase in other mark-to-market adjustments; an $18 million increase in agent fees due to rapid growth in FES' retail business; and a $17 million increase in intercompany billings. The intercompany billings increased due to higher merger-related costs, partially offset by lower leasehold costs from the Ohio Companies.
The inclusion of the Allegheny companies' operations added $1.6 billion to operating expenses as shown in the following table:
Source of Operating Expense Changes Increase (Decrease)
  (In millions)
Allegheny Companies  
Fuel $794
Purchased power 149
Fossil operation and maintenance 152
Transmission 198
Pensions and OPEB mark-to-market adjustment 44
Other mark-to-market 4
Depreciation 111
General taxes 40
Other 96
Total operating expenses $1,588
Other Expense —
Total other expense in 2011 was $453 million lower than 2010, primarily due to a $569 million gain on the partial sale of FEV's interest in Signal Peak and an increase in nuclear decommissioning trust investment income of $5 million, partially offset by a $121 million increase in net interest expense. The net interest expense increase in 2011 from 2010 resulted from lower capitalized interest due to the completion of major environmental projects in 2010.
Other — 2011 Compared to 2010
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 an $99 million decrease in earnings available to FirstEnergy in 2011 compared to 2010. The decrease resulted primarily from decreased capitalized interest and increased depreciation expense resulting from the completed construction projects placed into service ($58 million), decreased investment income ($16 million), an asset impairment charge in the first quarter of 2011 ($11 million) and higher income taxes ($13 million).
Summary of Results of Operations — 2010 Compared with 2009
Financial results for FirstEnergy’s major business segments in 2010 and 2009 were as follows:


64


2010 Financial Results Regulated Distribution Competitive Energy Services Regulated Independent Transmission Other and Reconciling Adjustments FirstEnergy Consolidated
  (In millions)
Revenues:          
External          
Electric $9,271
 $3,252
 $—
 $—
 $12,523
Other 300
 323
 242
 (123) 742
Internal 139
 2,301
 —
 (2,366) 74
Total Revenues 9,710
 5,876
 242
 (2,489) 13,339
           
Operating Expenses:          
Fuel —
 1,432
 —
 —
 1,432
Purchased power 5,273
 1,724
 —
 (2,373) 4,624
Other operating expenses 1,320
 1,393
 61
 (78) 2,696
Pensions and OPEB mark-to-market adjustment 82
 107
 (2) 3
 190
Provision for depreciation 433
 284
 37
 14
 768
Amortization of regulatory assets, net 712
 —
 10
 —
 722
General taxes 605
 124
 30
 17
 776
Impairment of long-lived assets —
 388
 —
 —
 388
Total Operating Expenses 8,425
 5,452
 136
 (2,417) 11,596
           
Operating Income 1,285
 424
 106
 (72) 1,743
           
Other Income (Expense):          
Investment income 102
 51
 —
 (36) 117
Interest expense (500) (232) (22) (91) (845)
Capitalized interest 4
 95
 2
 64
 165
Total Other Expense (394) (86) (20) (63) (563)
           
Income Before Income Taxes 891
 338
 86
 (135) 1,180
Income taxes 338
 128
 32
 (36) 462
Net Income 553
 210
 54
 (99) 718
Loss attributable to noncontrolling interest —
 —
 —
 (24) (24)
Earnings available to FirstEnergy Corp. $553
 $210
 $54
 $(75) $742



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2009 Financial Results Regulated Distribution Competitive Energy Services Regulated Independent Transmission Other and Reconciling Adjustments FirstEnergy Consolidated
  (In millions)
Revenues:          
External          
Electric $10,585
 $1,447
 $—
 $—
 $12,032
Other 331
 481
 223
 (111) 924
Internal —
 2,843
 —
 (2,826) 17
Total Revenues 10,916
 4,771
 223
 (2,937) 12,973
           
Operating Expenses:          
Fuel —
 1,153
 —
 —
 1,153
Purchased power 6,560
 996
 —
 (2,826) 4,730
Other operating expenses 1,257
 1,332
 56
 (94) 2,551
Pensions and OPEB mark-to-market adjustment 166
 151
 2
 2
 321
Provision for depreciation 426
 279
 37
 15
 757
Amortization of regulatory assets, net 1,006
 —
 13
 —
 1,019
General taxes 589
 112
 32
 20
 753
Impairment of long-lived assets —
 6
 —
 —
 6
Total Operating Expenses 10,004
 4,029
 140
 (2,883) 11,290
           
Operating Income 912
 742
 83
 (54) 1,683
           
Other Income (Expense):          
Investment income 141
 121
 —
 (58) 204
Interest expense (478) (174) (19) (307) (978)
Capitalized interest 3
 62
 1
 65
 131
Total Other Expense (334) 9
 (18) (300) (643)
           
Income Before Income Taxes 578
 751
 65
 (354) 1,040
Income taxes 243
 305
 26
 (390) 184
Net Income 335
 446
 39
 36
 856
Loss attributable to noncontrolling interest —
 —
 —
 (16) (16)
Earnings available to FirstEnergy Corp. $335
 $446
 $39
 $52
 $872


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Changes Between 2010 and 2009 Financial Results
Increase (Decrease)
 Regulated Distribution Competitive Energy Services Regulated Independent Transmission Other and Reconciling Adjustments FirstEnergy Consolidated
  (In millions)
Revenues:          
External          
Electric $(1,314) $1,805
 $—
 $—
 $491
Other (31) (158) 19
 (12) (182)
Internal 139
 (542) —
 460
 57
Total Revenues (1,206) 1,105
 19
 448
 366
           
Operating Expenses:          
Fuel —
 279
 —
 —
 279
Purchased power (1,287) 728
 —
 453
 (106)
Other operating expenses 63
 61
 5
 16
 145
Pensions and OPEB mark-to-market adjustment (84) (44) (4) 1
 (131)
Provision for depreciation 7
 5
 —
 (1) 11
Amortization of regulatory assets, net (294) —
 (3) —
 (297)
General taxes 16
 12
 (2) (3) 23
Impairment of long-lived assets —
 382
 —
 —
 382
Total Operating Expenses (1,579) 1,423
 (4) 466
 306
           
Operating Income 373
 (318) 23
 (18) 60
           
Other Income (Expense):          
Gain on partial sale of Signal Peak —
 —
 —
 —
 —
Investment income (39) (70) —
 22
 (87)
Interest expense (22) (58) (3) 216
 133
Capitalized interest 1
 33
 1
 (1) 34
Total Other Expense (60) (95) (2) 237
 80
           
Income Before Income Taxes 313
 (413) 21
 219
 140
Income taxes 95
 (177) 6
 354
 278
Net Income 218
 (236) 15
 (135) (138)
Loss attributable to noncontrolling interest —
 —
 —
 (8) (8)
Earnings available to FirstEnergy Corp. $218
 $(236) $15
 $(127) $(130)
Regulated Distribution — 2010 Compared with 2009
Net income increased by $218 million in 2010 compared to 2009, primarily due to CEI’s $216 million regulatory asset impairment in 2009 and 2010. Customer prepayments earn interest at 7.5%lower pensions and will be used to reduce electricity chargesOPEB costs, partially offset by increases in 2011 and 2012.other operating expenses. Lower generation revenues were offset by lower purchased power expenses.


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Revenues —
The decrease in total revenues resulted from the following sources:
Revenues by Type of Service 2010 2009 
Increase
(Decrease)
  (In millions)
Distribution services $3,629
 $3,419
 $210
Generation:      
Retail 4,457
 5,764
 (1,307)
Wholesale 702
 752
 (50)
Total generation sales 5,159
 6,516
 (1,357)
Transmission 596
 805
 (209)
Other 326
 176
 150
Total Revenues $9,710
 $10,916
 $(1,206)
The increase in distribution deliveries by customer class is summarized in the following table:
Electric Distribution MWH DeliveriesIncrease
Residential5.9%
Commercial2.8%
Industrial8.4%
Total Distribution MWH Deliveries5.6%
Higher deliveries to residential and commercial customers reflect increased weather-related usage due to a 70% increase in cooling degree days in 2010 compared to 2009, partially offset by a 4% decrease in heating degree days for the same period. In the industrial sector, MWH deliveries increased primarily to major automotive customers (16%), refinery customers (7%) and steel customers (38%). The increase in distribution service revenues also reflects Met-Ed's, Penelec's and Penn's recovery of the Pennsylvania EE&C as approved by the PPUC in March 31, 2009,2010 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 $1.4 billion decrease in generation revenues in 2010 compared to 2009:
Source of Change in Generation Revenues 
Increase
(Decrease)
  (In millions)
Retail:  
Effect of decrease in sales volumes $(1,435)
Change in prices 128
  (1,307)
Wholesale:  
Effect of decrease in sales volumes (64)
Change in prices 14
  (50)
Net Decrease in Generation Revenues $(1,357)
The decrease in retail generation sales volumes was primarily due to an increase in customer shopping in the Ohio Companies’ service territories. Total generation MWH provided by alternative suppliers as a percentage of total MWH deliveries by the Ohio Companies increased to 62% in 2010 from 17% in 2009.
The decrease in wholesale generation revenues reflected lower RPM revenues for Met-Ed and Penelec submitted their 5-year NUG Statement Compliance filingin the PJM market.
Transmission revenues decreased $209 million primarily due to the PPUCtermination of the Ohio Companies’ transmission tariff effective June 1, 2009; transmission costs are now a component of the cost of generation established under the May 2009 Ohio CBP.
Other revenues increased by $150 million primarily due to Met-Ed's and Penelec's PSA with FES in accordance with their 1998 Restructuring Settlement.2010, resulting in increased capacity revenues.


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Operating Expenses —
Total operating expenses decreased by $1.6 billion due to the following:
Purchased power costs were $1.3 billion lower in 2010, largely due to lower volume requirements. The decrease in volumes from non-affiliates resulted principally from the termination of a third-party supply contract for Met-Ed proposedand Penelec in January 2010 and from the increase in customer shopping in the Ohio Companies’ service territories. The decrease in purchases from FES also resulted from the increase in customer shopping in Ohio.
An increase in purchased power unit costs from non-affiliates in 2010 resulted from higher capacity prices in the PJM market for Met-Ed and Penelec. A decrease in unit costs for purchases from FES was principally due to reduce its CTC ratethe lower weighted average unit price per MWH established under the May 2009 CBP auction for the residential class with a corresponding increaseOhio Companies effective June 1, 2009.
Source of Change in Purchased Power 
Increase
(Decrease)
  (In millions)
Purchases from non-affiliates:  
Change due to increased unit costs $709
Change due to decreased volumes (1,489)
  (780)
Purchases from FES:  
Change due to decreased unit costs (257)
Change due to decreased volumes (250)
  (507)
Net Decrease in Purchased Power Costs $(1,287)
Transmission expenses increased $70 million primarily due to higher PJM network transmission expenses and congestion costs for Met-Ed and Penelec, partially offset by lower MISO network transmission expenses that are reflected in the generation rate established under the May 2009 Ohio CBP. Met-Ed and Penelec defer or amortize the difference between revenues from their transmission rider and transmission costs incurred, resulting in no material effect on current period earnings.
Energy efficiency program costs, which are also recovered through rates, increased $41 million in 2010 compared to 2009.
Labor and employee benefit expenses decreased by $30 million due to lower payroll costs resulting from staffing reductions implemented in 2009, and restructuring expenses recognized in 2009.
Pensions and OPEB mark-to-market adjustment charges decreased by $84 million primarily resulting from lower net actuarial losses.
Expenses for economic development commitments related to the Ohio Companies’ ESP were lower by $11 million in 2010 compared to 2009.
Depreciation expense increased $7 million due to property additions since 2009.
Amortization of regulatory assets decreased $294 million due primarily to the absence of the $216 million impairment of CEI’s regulatory assets in 2009, reduced net MISO and PJM transmission cost amortization and reduced CTC amortization for Met-Ed and Penelec, partially offset by increased amortization associated with the accelerated recovery of deferred distribution costs in Ohio and a $35 million regulatory asset impairment in 2010 associated with the Ohio Companies’ ESP and the shopping credit,absence of CEI’s purchased power cost deferrals that ended in early 2009.
General taxes increased $16 million principally due to a benefit relating to Ohio MWH excise taxes that was recognized in 2009 and applicable to prior years.
Other Expense —
Other expense increased $60 million in 2010 compared to 2009 primarily due to lower investment income on OE's and TE's nuclear decommissioning trusts ($37 million) and higher net interest expense associated with debt issuances during 2009 ($23 million).
Regulated Independent Transmission — 2010 Compared with 2009
Net income increased by $15 million in 2010 compared to 2009 due to increased revenues.


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Revenues —
Total revenues increased by $19 million principally due to higher peak loads in 2010 compared to 2009.
Operating Expenses —
Total operating expenses decreased by $4 million principally due to decreased property taxes and decreased pensions and OPEB costs primarily due to lower net actuarial losses.
Other Expense —
Other expense increased $2 million in 2010 due to higher interest expense associated with higher average debt levels in 2010 compared to 2009.
Competitive Energy Services — 2010 Compared to 2009
Net income decreased by $235 million in 2010 compared to 2009. The decrease in net income was primarily due to $382 million of impairment charges ($240 million net of tax) in 2010. In addition, FES sold a 6.65% participation interest in OVEC in 2010 compared to a 9% interest in 2009, accounting for $105 million of the reduction in net income. Investment income from nuclear decommissioning trusts was also lower in 2010. These reductions were partially offset by an increase in sales margins.
Revenues —
Total revenues increased $1.1 billion in 2010 compared to the same period in 2009 primarily due to an increase in direct and governmental aggregation sales and sales of RECs, partially offset by decreases in POLR sales to the Ohio Companies, other wholesale sales and the reduced OVEC participation interest sale in 2010.
The increase in reported segment revenues resulted from the following sources:
Revenues by Type of Service 2010 2009 Increase (Decrease)
  (In millions)
Direct and Governmental Aggregation $2,493
 $779
 $1,714
POLR 2,589
 2,863
 (274)
Wholesale 397
 632
 (235)
Transmission 77
 73
 4
RECs 74
 17
 57
Sale of OVEC participation interest 85
 252
 (167)
Other 161
 155
 6
Total Revenues $5,876
 $4,771
 $1,105
The increase in direct and governmental aggregation revenues of $1.7 billion resulted from increased revenue from the acquisition of new commercial and industrial customers as well as from new governmental aggregation contracts with communities in Ohio that provide generation to 1.5 million residential and small commercial customers at the end of 2010 compared to approximately 600,000 customers at the end of 2009. Increases in direct sales were partially offset by lower unit prices. Sales to residential and small commercial customers were also bolstered by summer weather in the delivery area that was significantly warmer than in 2009.
The decrease in POLR revenues of $274 million was due to lower sales volumes and lower unit prices to the Ohio Companies, partially offset by increased sales volumes and higher unit prices to Met-Ed and Penelec. The lower sales volumes and unit prices to the Ohio Companies in 2010 reflected the results of the May 2009 CBP. The increased revenues to Met-Ed and Penelec proposedresulted from FES supplying volumes previously supplied through a third-party contract, and at prices that were slightly higher than in 2009.
Other wholesale revenues decreased $235 million due to reduce its CTC ratereduced volumes, partially offset by higher prices. Lower sales volumes in MISO were due to zero for all classes with a correspondingavailable capacity serving increased retail sales in Ohio partially offset by increased sales under bilateral agreements in PJM.


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The following tables summarize the price and volume factors contributing to changes in revenues from generation sales:
Source of Change in Direct and Governmental Aggregation Increase (Decrease)
  (In millions)
Direct Sales:  
Effect of increase in sales volumes $1,080
Change in prices (87)
  993
Government Aggregation:  
Effect of increase in sales volumes 707
Change in prices 14
  721
Net Increase in Direct and Governmental Aggregation Revenues $1,714
Source of Change in Wholesale Revenues Increase (Decrease)
  (In millions)
POLR:  
Effect of increase in sales volumes $38
Change in prices (312)
  (274)
Other Wholesale:  
Effect of decrease in sales volumes (344)
Change in prices 109
  (235)
Net Decrease in Wholesale Revenues $(509)
Operating Expenses —
Total operating expenses increased $1.4 billion in 2010 due to the following factors:
Fuel costs increased $279 million in 2010 compared to 2009 primarily due to increased volumes consumed ($217 million) and higher unit prices ($62 million). The higher volumes consumed in 2010 were due to increased sales to direct and governmental aggregation customers, improved economic conditions and improved generating unit availability. The increase in unit prices was due primarily to increased coal transportation costs and to higher nuclear fuel unit prices following the refueling outages that occurred in 2009 and 2010.
Purchased power costs increased $728 million. Increased volumes purchased primarily relate to the assumption of a 1,300 MW third party contract from Met-Ed and Penelec.
Fossil operating costs decreased $12 million due primarily to lower labor and professional and contractor costs, which were partially offset by reduced gains from the sale of emission allowances and excess coal.
Nuclear operating costs decreased $21 million due primarily to lower labor, consulting and contractor costs partially offset by increased nuclear property insurance and employee benefit costs. The year 2010 had one less refueling outage and fewer extended outages than the same period of 2009.
Transmission expenses increased $25 million due primarily to increased costs in MISO of $170 million from higher network, ancillary and congestion costs, partially offset by lower PJM transmission expenses of $145 million due to lower congestion costs.
Depreciation expense increased $5 million principally due to property additions that were placed in service since 2009.
General taxes increased $12 million due to an increase in revenue-related taxes.
Other operating expenses increased $406 million primarily due to a $382 million impairment charge ($240 million net of tax) related to operational changes at certain smaller coal-fired units. Expenses also increased for professional and contractor services, billings from affiliated service companies, uncollectible customer accounts and agent fees, as FES continued to grow its retail business.


71


Other Expense —
Total other expense in 2010 was $95 million higher than the same period in 2009, primarily due to a $66 million decrease in nuclear decommissioning trust investment income and a $25 million increase in net interest expense from new long-term debt issued in late 2009 combined with the restructuring of outstanding PCRBs that occurred throughout 2009 and 2010.
Other — 2010 Compared to 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 $127 million decrease in earnings available to FirstEnergy in 2010 compared to 2009. The decrease resulted primarily from increased income tax expense ($354 million) due in part to the absence of favorable tax settlements that occurred in 2009 ($200 million), partially offset by the absence of 2009 debt retirement costs in connection with the tender offer for holding company debt ($90 million),decreased interest expense associated with the debt retirement ($53 million) and increased investment income ($22 million).
CAPITAL RESOURCES AND LIQUIDITY
As of December 31, 2011, FirstEnergy had $202 million of cash and cash equivalents available to fund investments, operations and capital expenditures.
FirstEnergy expects its existing sources of liquidity to remain sufficient to meet its anticipated obligations and those of its subsidiaries. FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. In addition to internal sources to fund liquidity and capital requirements for 2012 and beyond, FirstEnergy expects to rely on external sources of funds. Short-term cash requirements not met by cash provided from operations are generally satisfied through short-term borrowings. Long-term cash needs may be met through issuances of debt and/or equity securities. FirstEnergy expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements along with continued access to long-term capital markets.
A material adverse change in operations, or in the availability of external financing sources, could impact FirstEnergy’s liquidity position and ability to fund its capital requirements. To mitigate risk, FirstEnergy’s business strategy stresses financial discipline and a strong focus on execution. Major elements include the expectation of: adequate cash from operations, opportunities for favorable long-term earnings growth in the competitive generation markets, operational excellence, business plan execution, well-positioned generation fleet, no speculative trading operations, appropriate long-term commodity hedging positions, manageable capital expenditure program, adequately funded pension plan, minimal near-term maturities of existing long-term debt, commitment to a secure dividend and a successful merger integration.
As of December 31, 2011, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was principally due to currently payable long-term debt, which, as of December 31, 2011, included the following:
Currently Payable Long-term Debt (In millions)
Met-Ed, Penelec, FGCO and NGC PCRBs supported by bank LOCs (1)
 $632
AE Supply unsecured note 503
FGCO and NGC unsecured PCRBs (1)
 270
WP unsecured note 80
NGC collateralized lease obligation bonds 67
Sinking fund requirements 52
Other notes 17
  $1,621
(1)
These PCRBs are classified as currently payable long-term debt solely because the applicable Interest rate mode permits individual debt holders to put the respective debt back to the issuer prior to maturity.


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Short-Term Borrowings
FirstEnergy hadnosignificant short-term borrowings as of December 31, 2011, and short-term borrowings of approximately $700 millionas ofDecember 31, 2010. FirstEnergy’s available liquidity as of January 31, 2012, was as follows:
Company Type Maturity Commitment Available Liquidity
      (In millions)
FirstEnergy(1)
 Revolving June 2016 $2,000
 $1,395
FES / AE Supply Revolving June 2016 2,500
 2,498
TrAIL Revolving Jan. 2013 450
 450
AGC Revolving Dec. 2013 50
 —
    Subtotal $5,000
 $4,343
    Cash —
 49
    Total $5,000
 $4,392
(1)
FE and the Utilities
Revolving Credit Facilities
FirstEnergy and FES / AE Supply Facilities
FirstEnergy and certain of its subsidiaries participate in two five-year syndicated revolving credit facilities with aggregate commitments of$4.5 billion(Facilities).
An aggregate amount of$2 billionis available to be borrowed under a syndicated revolving credit facility (FirstEnergy Facility), subject to separate borrowing sublimits for each borrower. The borrowers under the FirstEnergy Facility are FE, OE, Penn, CEI, TE, Met-Ed, ATSI, JCP&L, MP, Penelec, PE and WP. An additional$2.5 billionis available to be borrowed by FES and AE Supply under a separate syndicated revolving credit facility (FES/AE Supply Facility), subject to separate borrowing sublimits for each borrower.
Commitments under each of the Facilities will be available until June 17, 2016, unless the lenders agree, at the request of the applicable borrowers, to up to two additional one-year extensions. Generally, borrowings under each of the Facilities are available to each borrower separately and mature on the earlier of364days from the date of borrowing or the commitment termination date, as the same may be extended.
Borrowings under each of the Facilities are subject to the usual and customary provisions for acceleration upon the occurrence of events of default, including a cross-default for other indebtedness in excess of$100 million, as described further in Note 12, Capitalization.
The following table summarizes the borrowing sub-limits for each borrower under the Facilities, 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 ofDecember 31, 2011:


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Borrower Revolving Credit Facility Sub-Limit Regulatory and Other Short-Term Debt Limitations 
  (In millions) 
FE  $2,000
  —
(1) 
FES  $1,500
  —
(2) 
AE Supply  $1,000
  —
(2) 
OE  $500
  $500
 
CEI  $500
  $500
 
TE  $500
  $500
 
JCP&L  $425
  $411
(3) 
Met-Ed  $300
  $300
(3) 
Penelec  $300
  $300
(3) 
West Penn  $200
  $200
(3) 
MP  $150
  $150
(3) 
PE  $150
  $150
(3) 
ATSI  $100
  $100
 
Penn  $50
  $33
(3) 
(1)
No limitations.
(2)
No limitation based upon blanket financing authorization from the FERC under existing open market tariffs.
(3)
Excluding amounts which may be borrowed under the regulated companies’ money pool.
The entire amount of the FES/AE Supply Facility and$700 millionof the FirstEnergy Facility, subject to each borrower’s sub-limit, is available for 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 each of the Facilities and against the applicable borrower’s borrowing sub-limit.
Each of the Facilities 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 December 31, 2011, FirstEnergy’s and its subsidiaries’ debt to total capitalization ratios (as defined under each of the Facilities) were as follows:
Borrower
FirstEnergy57.5%
FES51.4%
OE63.4%
Penn42.8%
CEI59.4%
TE62.7%
JCP&L43.6%
Met-Ed56.0%
Penelec56.6%
ATSI48.6%
MP56.6%
PE56.8%
WP52.1%
AE Supply38.5%
As of December 31, 2011, FirstEnergy could issue additional debt of approximately $6.7 billion, or recognize a reduction in equity of approximately $3.6 billion, and remain within the limitations of the financial covenants required by its revolving credit facility.
The Facilities do not contain provisions that restrict the ability to borrow or accelerate payment of outstanding advances as a result of any change in credit ratings. Pricing is subject to “pricing grids,” whereby the borrower's cost of funds borrowed under the Facilities is related to the credit ratings of the company borrowing the funds.


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AGC and TrAIL Revolving Credit Facilities
FirstEnergy also has established$500 millionof revolving credit facilities that are available to TrAIL ($450 million) and AGC($50 million) until January 2013 and December 2013, respectively.
Under the terms of its credit facility, outstanding debt of AGC may not exceed 65% of the sum of its debt and equity as of the last day of each calendar quarter. Outstanding debt for TrAIL may not exceed 65% of the sum of its debt and equity as of the last day of each calendar quarter through December 31, 2012. These provisions limit debt levels of these subsidiaries and also limit the net assets of each subsidiary that may be transferred to AE. As of December 31, 2011, the debt to total capitalization ratios for TrAIL and AGC (as defined under each of their credit facilities) were 48% and 51%, respectively.

As of December 31, 2011, TrAIL could issue additional debt of approximately $222 million, or recognize a reduction in equity of approximately $341 million and AGC could issue additional debt of approximately $39 million, or recognize a reduction in equity of approximately $61 million, and remain within the limitations of the financial covenants required by their credit facilities.
FirstEnergy Money Pools
FirstEnergy’s regulated companies also have the ability to borrow from each other and the shopping credit. holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy’s unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool.The average interest rate for borrowings during 2011 was0.44% per annum for the regulated companies’ money pool and0.42% per annum for the unregulated companies’ money pool.
Pollution Control Revenue Bonds
As of December 31, 2011, FirstEnergy’s currently payable long-term debt included approximately $632 million (FES — $558 million, 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 as of December 31, 2011:
LOC Bank 
Aggregate LOC
Amount(1)
 LOC Termination Date 
Reimbursements
of LOC Draws Due
  (In millions)    
UBS $272
 April 2014 April 2014
CitiBank N.A. 165
 June 2014 June 2014
Wachovia Bank 153
 March 2014 March 2014
The Bank of Nova Scotia 49
 April 2014 
Multiple dates(2)
Total $639
    
(1)
Includes approximately $7 million of applicable interest coverage.
(2)
Shorter of 6 months or LOC termination date.
During 2011, FirstEnergy redeemed or repurchased approximately $520.4 million principal amount of PCRBs, as summarized in the following table. Approximately $28.5 million of FGCO FMBs and $98.9 million of NGC FMBs associated with the PCRBs were returned for cancellation by the associated LOC providers.
SubsidiariesAmount 
 (In millions) 
AE Supply$53.0
(1) 
FGCO$198.2
(2) 
NGC$213.5
(2) 
MP$70.2
(1) 
(1)
Includes $14.4 million of PCRBs redeemed for which MP and AE Supply are co-obligors.
(2)
Subject to market conditions, these PCRBs are being held for future remarketing.


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Long-Term Debt Capacity
As ofDecember 31, 2011, the Ohio Companies and Penn had the aggregate capability to issue approximately$2.7 billionof 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$232 millionand$20 million, respectively. As a result of the indenture provisions, TE cannot incur any additional secured debt. Met-Ed and Penelec had the capability to issue secured debt of approximately$376 millionand$382 million, respectively, under provisions of their senior note indentures as ofDecember 31, 2011. In addition, based upon their respective FMB indentures, net earnings and available bondable property additions as ofDecember 31, 2011, MP, PE and WP had the capability to issue approximately$1.1 billionof additional FMBs in the aggregate. These companies may be further limited by the financial covenants of the Facilities and subject to current regulatory approvals and applicable statutory and/or charter limitations.
Based upon FGCO’s net earnings and available bondable property additions under its FMB indentures as ofDecember 31, 2011, FGCO had the capability to issue$2.1 billionof additional FMBs under the terms of that indenture. Based upon NGC’s net earnings and available bondable property additions under its FMB indenture as ofDecember 31, 2011, NGC had the capability to issue$2.0 billionof additional FMBs under the terms of that indenture.
FirstEnergy’s access to capital markets and costs of financing are influenced by the credit ratings of its securities. On March 21, 2011, S&P affirmed the ratings and stable outlook of FirstEnergy and its subsidiaries. On May 27, 2011, Fitch upgraded ratings for certain subsidiaries and revised the outlook to stable from negative for FirstEnergy and FES. On August 18, 2011, Moody's downgraded ratings for FES to Baa3 from Baa2 and revised FES' outlook to stable. On January 18, 2012, Moody's upgraded ratings for TrAIL to A3 from Baa2. The following table displays FirstEnergy’s and its subsidiaries’ debt credit ratings as of February 24, 2012:
Senior SecuredSenior Unsecured
IssuerS&PMoody’sFitchS&PMoody’sFitch
FE———BB+Baa3BBB
FES———BBB-Baa3BBB
AE Supply———BBB-Baa3BBB-
AGC———BBB-Baa3BBB
ATSI———BBB-Baa1A-
CEIBBBBaa1BBBBBB-Baa3BBB-
JCP&L———BBB-Baa2BBB+
Met-EdBBBA3A-BBB-Baa2BBB+
MPBBB+Baa1A-BBB-Baa3BBB+
OEBBBA3BBB+BBB-Baa2BBB
PenelecBBBA3BBB+BBB-Baa2BBB
PennBBB+A3BBB+———
PEBBB+Baa1A-BBB-Baa3BBB+
TEBBBBaa1BBB———
TrAIL———BBB-A3A-
WPBBB+A3A-BBB-Baa2BBB+
See Note 12, Capitalization of the Combined Notes to the Consolidated Financial Statements for additional information on FirstEnergy's and the Registrants' long-term debt and other long-term obligations that were outstanding as of December 31, 2011.
Changes in Cash Position
As of December 31, 2011, FirstEnergy had $202 million of cash and cash equivalents compared to approximately $1 billion as of December 31, 2010. As of December 31, 2011 and 2010, FirstEnergy had approximately $79 million and $13 million, respectively, of restricted cash included in other current assets on the Consolidated Balance Sheet.
During 2011, FirstEnergy received $1.8 billion of cash dividends from its subsidiaries and paid$881 millionin cash dividends to common shareholders, including $20 million paid in March by AE to its former shareholders.


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Cash Flows From Operating Activities
FirstEnergy’s consolidated net cash from operating activities is provided primarily by its regulated distribution, regulated independent transmission and competitive energy services businesses (see Results of Operations above). Net cash provided from operating activities was $3.1 billion in 2011, $3.1 billion in 2010 and $2.5 billion in 2009, as summarized in the following table:
Operating Cash Flows 2011 2010 2009
  (In millions)
Net income $869
 $718
 $856
Non-cash charges 2,424
 2,343
 2,095
Pension trust contributions (372) —
 (500)
Working capital and other 142
 15
 14
  $3,063
 $3,076
 $2,465
The 2011 increase in non-cash charges is primarily due to increased pensions and OPEB mark-to-market adjustment charges from higher actuarial losses ($317 million), increased deferred taxes resulting from bonus depreciation ($348 million) and increased depreciation attributable to the acquired Allegheny companies ($353 million). These increases were partially offset by gains from the sale of assets, mostly due to the sale of Signal Peak ($543 million), and lower amortization of regulatory assets from reduced net PJM transmission cost and transition cost recovery ($393 million).
The 2011 increase in cash flows from working capital and other is primarily due to decreased receivables from higher customer collections ($324 million) partially offset by the absence of interest rate swap activity transacted in 2010 ($129 million).
Cash Flows From Financing Activities
In 2011, cash used for financing activities was $2,924 million compared to $983 million in 2010. The following table summarizessecurity issuances (net of any discounts) and redemptions:
Securities Issued or Redeemed 2011 2010 2009
    (In millions)  
New Issues      
PCRBs $272
 $740
 $940
Long-term revolving credit 70
 —
 —
Senior secured notes —
 350
 297
FMBs —
 —
 398
Unsecured Notes 262
 9
 2,997
  $604
 $1,099
 $4,632
Redemptions      
PCRBs $792
 $741
 $884
Long-term revolving credit 495
 —
 —
Senior secured notes 460
 141
 217
FMBs 15
 32
 1
Unsecured notes 147
 101
 1,508
  $1,909
 $1,015
 $2,610
       
Net repayment of short-term borrowings $(700) $(378) $(1,246)
Cash Flows From Investing Activities
Cash used for investing activities in 2011 resulted from cash used for property additions, partially offset by the cash acquired in the Allegheny merger and proceeds from asset sales. The following table summarizes investing activities for 2011, 2010 and 2009 by business segment:


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Summary of Cash Flows
Provided from (Used for) Investing Activities
 
Property
Additions
 Investments Other Total
    (In millions)  
Sources (Uses)        
2011        
Regulated distribution $(1,060) $30
 $(83) $(1,113)
Competitive energy services (927) 545
 3
 (379)
Regulated independent transmission (192) —
 (3) (195)
Cash received in Allegheny merger —
 590
 —
 590
Other and reconciling adjustments (99) 223
 17
 141
Total $(2,278) $1,388
 $(66) $(956)
         
2010        
Regulated distribution $(681) $96
 $17
 $(568)
Competitive energy services (1,159) (43) (51) (1,253)
Regulated independent transmission (64) —
 (4) (68)
Other and reconciling adjustments (59) (30) 30
 (59)
Total $(1,963) $23
 $(8) $(1,948)
         
2009        
Regulated distribution $(718) $39
 $(45) $(724)
Competitive energy services (1,412) (8) (19) (1,439)
Regulated independent transmission (32) —
 (1) (33)
Other and reconciling adjustments (41) (27) 79
 11
Total $(2,203) $4
 $14
 $(2,185)
Net cash used for investing activities in 2011 decreased by $992 million compared to 2010. The decrease was principally due to cash acquired in the Allegheny merger ($590 million) and an increase in proceeds from asset sales ($723 million), partially offset by increased property additions ($315 million).
Our capital spending for 2012 is expected to be approximately$2.1 billion(excluding nuclear fuel).For 2013, we anticipate baseline capital expenditures of approximately $2.0 billion, which exclude any potential additional strategic opportunities, future mandated spending, energy efficiency or environmental spending relating to MATS. Planned capital initiatives are intended to promote reliability, improve operations, and support current environmental and energy efficiency directives.Our capital investments for additional nuclear fuel are expected to be $280 million and $219 million in 2012 and 2013, respectively.
CONTRACTUAL OBLIGATIONS
As of December 31, 2011, our estimated cash payments under existing contractual obligations that we consider firm obligations are as follows:
Contractual Obligations Total 2012 2013-2014 2015-2016 Thereafter
  (In millions)
Long-term debt(1)
 $17,005
 $1,605
 $2,192
 $2,688
 $10,520
Interest on long-term debt(2)
 12,071
 975
 1,804
 1,548
 7,744
Operating leases(3)
 3,147
 258
 492
 598
 1,799
Fuel and purchased power(4)
 32,877
 3,598
 5,589
 4,616
 19,074
Capital expenditures 2,715
 681
 984
 638
 412
Pension funding 1,030
 —
 231
 799
 —
Other(5)
 263
 28
 105
 47
 83
Total $69,108
 $7,145
 $11,397
 $10,934
 $39,632
(1)
Excludes unamortized discounts and premiums and fair value accounting adjustments.
(2)
Interest on variable-rate debt based on rates as of December 31, 2011.
(3)
See Note 6, Leases of the Combined Notes to the Consolidated Financial Statements.
(4)
Amounts under contract with fixed or minimum quantities based on estimated annual requirements.
(5)
Includes amounts for capital leases (see Note 6, Leases of the Combined Notes to the Consolidated Financial Statements) and contingent tax liabilities (see Note 5, Taxes of the Combined Notes to the Consolidated Financial Statements).


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Excluded from the data shown above are estimates for the cash outlays stemming from power purchase contracts entered into by most of the Utilities and under which they procure the power supply necessary to provide generation service to their customers who do not choose an alternative supplier. The exact amounts will be determined by future customer behavior and consumption levels, but based on numerous planning assumptions, management estimates an amount of $5.4 billion in 2012, $1.8 billion of which relates to contracts with FES.
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. 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 credit support to various providers for the financing or refinancing by subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements include provisions for parent guarantees, surety bonds and/or LOCs to be issued by FirstEnergy on behalf of one or more of its subsidiaries. Additionally, certain contracts may contain collateral provisions that are contingent upon either FirstEnergy's or its subsidiaries’ credit ratings.
As of December 31, 2011, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $3.7 billion, as summarized below:
Guarantees and Other Assurances Maximum Exposure
  (In millions)
FirstEnergy Guarantees on Behalf of its Subsidiaries  
Energy and Energy-Related Contracts(1)
 $268
LOC (long-term debt) - interest coverage(2)
 5
OVEC obligations 300
Other(3)
 301
  874
   
Subsidiaries’ Guarantees  
Energy and Energy-Related Contracts 141
LOC (long-term debt) - interest coverage(2)
 2
FES’ guarantee of NGC’s nuclear property insurance 79
FES’ guarantee of FGCO’s sale and leaseback obligations 2,286
Other 12
  2,520
   
Surety Bonds 151
LOCs(4)
 189
  340
Total Guarantees and Other Assurances $3,734
(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 $632 million is reflected in currently payable long-term debt on FirstEnergy's consolidated balance sheets.
(3)
Includes guarantees of $95 million for nuclear decommissioning funding assurances, $161 million supporting OE’s sale and leaseback arrangement, and $36 million for railcar leases.
(4)
Includes $36 million issued for various terms pursuant to capacity available under FirstEnergy’s revolving credit facility, $116 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $37 million pledged in connection with the sale and leaseback of Perry by OE.
Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of$151 millionprovide 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.
While the types of guarantees discussed above are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a senior unsecured credit rating downgrade to below S&P's BBB- and Moody's Baa3 and lower, or a “material adverse event,” the immediate posting of collateral or accelerated payments may be required of the subsidiary. As ofDecember 31, 2011, FirstEnergy’s exposure to additional credit contingent contractual obligations was$636 million, as shown below:


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Collateral Provisions FES AE Supply Utilities Total
  (In millions)
Credit rating downgrade to below investment grade (1)
 $468
 $8
 $57
 $533
Material adverse event (2)
 31
 60
 12
 103
Total $499
 $68
 $69
 $636
(1)
Includes $205 million and $47 million that are also considered accelerations of payment or funding obligations for FES and the Utilities, respectively.
(2)
Includes $31 million that is also considered an acceleration of payment or funding obligation at FES.

Certain bilateral non-affiliate contracts entered into by the Competitive Energy Services segment contain margining provisions that require posting of collateral. Based on FES' and AE Supply's power portfolios exposure as of December 31, 2011, FES and AE Supply have posted collateral of$88 millionand$1 million, respectively. Depending on the volume of forward contracts and future price movements, higher amounts for margining could be required.

Not included in the preceding information is potential collateral arising from the PSAs between FES or AE Supply and affiliated utilities in the Regulated Distribution Segment. As of December 31, 2011, neither FES nor AE Supply had any collateral posted with their affiliates. In the event of a senior unsecured credit rating downgrade to below S&P's BB- or Moody's Ba3, FES and AE Supply would be required to post$49 millionand$24 million, respectively.

FES' debt obligations are generally guaranteed by its subsidiaries, FGCO and NGC, and FES guarantees the debt obligations of each of FGCO and NGC. Accordingly, present and future holders of indebtedness of FES, FGCO and NGC would have claims against each of FES, FGCO and NGC, regardless of whether their primary obligor is FES, FGCO or NGC.
Signal Peak and Global Rail are borrowers under a $350 million syndicated two-year senior secured term loan facility due in October 2012. FirstEnergy, together with WMB Loan Ventures, LLC and WMB Loan Ventures II, LLC, the entities that previously shared ownership in the borrowers with FEV, have provided a guaranty of the borrowers' obligations under the facility. On October 18, 2011, FEV sold a portion of its ownership interest in Signal Peak and Global Rail (see Note 8, Variable Interest Entities). Following the sale, FirstEnergy, WMB Loan Ventures, LLC and WMB Loan Ventures II, LLC, together with Global Mining Group, LLC and Global Holding will continue to guarantee the borrowers' obligations until either the facility is replaced with non-recourse financing (no later than June 30, 2012) or replaced with appropriate recourse financing no earlier than September 4, 2012, that provides for separate guarantees from each owner in proportion with each equity owner's percentage ownership in the joint venture. In addition, FEV, Global Mining Group, LLC and Global Holding, the entities that own direct and indirect equity interests in the borrowers, have pledged those interests to the lenders under the current facility as collateral.
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 changessale and leaseback operating lease commitments, net of trust investments, was $1.6 billion as of December 31, 2011. See Note 6, Leases of the Combined Notes to the Consolidated Financial Statements for further information on FirstEnergy's and the Registrants' leases.
MARKET RISK INFORMATION
FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.
Commodity Price Risk
FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. FirstEnergy's Risk Management 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 practice. FirstEnergy uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.
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 9, Fair Value Measurements of the Combined Notes to the Consolidated Financial Statements). Sources of information for the valuation of commodity derivative contracts assets and liabilities as of December 31, 2011 are summarized by year in the following table:


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Source of Information-
Fair Value by Contract Year
 2012 2013 2014 2015 2016 Thereafter Total
  (In millions)
Prices actively quoted(1)
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Other external sources(2)
 (211) (51) (32) (22) —
 —
 (316)
Prices based on models (21) —
 —
 —
 8
 31
 18
Total(3)
 $(232) $(51) $(32) $(22) $8
 $31
 $(298)
(1)
Represents exchange traded New York Mercantile Exchange futures and options.
(2)
Primarily represents contracts based on broker and IntercontinentalExchange quotes.
(3)
Includes $(301) million in non-hedge commodity derivative contracts that are primarily related to NUG contracts. NUG contracts are subject to regulatory accounting and do not materially impact earnings.
FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. Based on derivative contracts held as of December 31, 2011, an adverse 10% change in commodity prices would decrease net income by approximately $13 million during the next 12 months.
Interest Rate Risk
FirstEnergy’s exposure to fluctuations in market interest rates is reduced since a significant portion of debt has fixed interest rates, as noted in the table below. FirstEnergy is subject to the inherent interest rate risks related to refinancing maturing debt by issuing new debt securities. As discussed in Note 6, Leases of the Combined Notes to the Consolidated Financial Statements, FirstEnergy’s investments in capital trusts effectively reduce future lease obligations, also reducing interest rate risk.
Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income $89
 $100
 $110
 $76
 $23
 $2,008
 $2,406
 $2,456
Average interest rate 8.8% 8.9% 9.0% 9.5% 10.3% 5.4% 6.0%  
Liabilities:                
Long-term Debt:                
Fixed rate $751
 $964
 $866
 $1,330
 $891
 $11,628
 $16,430
 $18,585
Average interest rate 7.3% 5.9% 5.4% 4.7% 5.9% 6.2% 6.1%  
Variable rate 
 $150
 
 
 
 $585
 $735
 $735
Average interest rate   1.8%       0.1% 0.4%  
Equity Price Risk
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 provides a portion of non-contributory pre-retirement basic life insurance for employees who are eligible to retire. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.
The benefit plan assets and obligations are remeasured annually using a December 31 measurement date or as significant triggering events occur. As of December 31, 2011, the FirstEnergy pension plan was invested in approximately 19% of equity securities, 48% of fixed income securities, 21% of absolute return strategies, 6% of real estate, 2% of private equity and 4% of cash. A decline in the value of pension plan assets could result in additional funding requirements. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. During 2011, FirstEnergy made pre-tax contributions to its qualified pension plans of $372 million. FirstEnergy made an additional $600 million pre-tax contribution to the qualified pension plan on January 5, 2012.
NDT funds have been established to satisfy NGC’s and certain of the Utilities’ nuclear decommissioning obligations. As of December 31, 2011, approximately 79% of the funds were invested in fixed income securities, 12% of the funds were invested in equity


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securities and 9% were invested in short-term investments, with limitations related to concentration and investment grade ratings. The investments are carried at their market values of approximately $1,699 million, $258 million and $207 million for fixed income securities, equity securities and short-term investments, respectively, as of December 31, 2011, excluding ($52) million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in additional annual generation revenue (Met-Ed - $27a $26 million and Penelec - $59 million), overall rates would remain unchanged. On July 30, 2009, the PPUC entered an order approving the 5-year NUG Statement, approving the reduction in fair value as of the CTC, and directing Met-Ed and Penelec to file a tariff supplement implementing this change. On JulyDecember 31, 2009, Met-Ed and Penelec filed tariff supplements decreasing the CTC rate in compliance with the July 30, 2009 order, and increasing the generation rate in compliance with the Pennsylvania Companies’ Restructuring Orders2011. The decommissioning trusts of 1998. On August 14, 2009, the PPUC issued Secretarial Letters approving Met-Ed and Penelec’s compliance filings.

By Tentative Order entered September 17, 2009, the PPUC provided for an additional 30-day comment period on whether “the Restructuring Settlement allows NUG over-collection for select and isolated months to be used to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists.”   In response to the Tentative Order, 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 filed comments objecting to the above accounting method utilized by Met-Ed and Penelec. Met-Ed and Penelec filed reply comments on October 26, 2009. On November 5, 2009, the PPUC issued a Secretarial Letter allowing parties to file reply comments to Met-Ed and Penelec’s reply comments by November 16, 2009, and reply comments were filed by the Office of Consumer Advocate, ARIPPA, and the Met-Ed Industrial Users Group and Penelec Industrial Customer Alliance.JCP&L, Met-Ed and Penelec are awaiting further action bysubject to regulatory accounting, with unrealized gains and losses recorded as regulatory assets or liabilities, since the PPUC.

On February 8, 2010, Penn filed withdifference between investments held in trust and the PPUCdecommissioning liabilities will be recovered from or refunded to customers. NGC, OE and TE recognized in earnings the unrealized losses on available-for-sale securities held in their NDT as OTTI. A decline in the value of FirstEnergy’s NDT or a generation procurement plan covering the period June 1, 2011 through May 31, 2013. The 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 proposed a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. The PPUC is required to issue an order on the plan no later than November 8, 2010.

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 December 30, 2009, the accumulated deferred cost balance totaled approximately $98 million.

In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004, supporting continuation of the current level and duration of the funding of TMI-2significant escalation in estimated 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 resultedcould result in an updated total decommissioning cost estimate of $729additional funding requirements. During 2011, approximately $1 million, (in 2003 dollars) compared$4 million and $1 million was contributed to the estimated $528NDTs of JCP&L, OE and TE, respectively. FENOC has submitted a $95 million (in 2003 dollars) from parental guarantee to the prior 1995 decommissioning study. The DPA filed comments on February 28, 2005 requesting thatNRC for a short-fall in nuclear 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 MayBeaver Valley Unit 1 and November 2007 and also submitted comments in the proceeding in November 2007. A schedule for further NJBPU proceedings has not yet been set. On March 13, 2009, JCP&L filed its annual SBC Petition with the NJBPU that includes a request for a reduction in the level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009. This matter is currently pending before the NJBPU.Perry.

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:

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

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

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

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

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

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

In support of former New Jersey Governor 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 NJBPU on August 19, 2009, and implementation began 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. 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. 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, with another Company, filed an additional settlement agreement with FERC to resolve their outstanding claims. FirstEnergy is actively pursuing settlement agreements with other parties to the case.  On December 8, 2009, certain parties sought a writ of mandamus from the DC Circuit Court of Appeals directing FERC to issue an order on the Initial Decision. The Court agreed to hold this matter in abeyance based upon FERC’s representation to use good faith efforts to issue a substantive ruling on the initial decision no later than May 27, 2010.  If FERC fails to act, the case will be submitted for briefing in June. The outcome of this matter cannot be predicted.

93
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 on the content of the compliance filings 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’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 at500kV or higher are


9


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 than500kV, however, are to be allocated on a load flow methodology, which is generally referred to as a “beneficiary pays” basis. The FERC found that PJM’s current beneficiary-paysapproach to allocating the cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.high voltage transmission facilities.

On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. On February 11, 2008, the FERC’s April 19, 2007, and January 31, 2008, orders wereFERC's Opinion 494 order was appealed to the federalU.S. Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the PUCO and another party have also appealed these orders to the Seventh Circuit, Court of Appeals. The appeals of these parties and others were consolidated for argument in the Seventh Circuit and the Seventh Circuit Court of Appealswhich issued a decision onin August 6, 2009. The court affirmed FERC's ratemaking treatment for existing transmission facilities, but found that FERC had not marshaled enough evidence to supportsupported its decision to allocate costs for new 500+ 500kV and higher voltage facilities on a postage-stampload ratio share basis and, based on this finding, remanded the rate design issue back to FERC. A request for rehearing and rehearing en banc by two Companies 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.

In an order dated January 21, 2010, FERC set the matter for a “paper hearings” – meaning that FERC called forhearing” and requested parties to submit comments or written testimonycomments pursuant to the schedule described in the order. FERC identifiednineseparate issues for comments and directed PJM to file the first round of comments on February 22, 2010, with other parties submitting responsive comments and then reply comments on later dates. PJM filed certain studies with FERC on April 8,13, 2010, and May 10, 2010.

The FERC’s orders on PJM rate design preventedin response to the FERC order. PJM's filing demonstrated that 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 abovehigh voltage transmission facilities on a postage-stampbeneficiary pays basis reducesresults in certain load serving entities in PJM bearing the majority of the 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. Other utilities and state commissions supported continued socialization of futurethese costs on a load ratio share basis. This matter is awaiting action by FERC. FirstEnergy cannot predict the outcome of this matter or estimate the possible loss or range of loss.

RTO Realignment

On June 1, 2011, ATSI and the ATSI zone entered into PJM. The move was performed as planned with no known operational or reliability issues for ATSI or for the wholesale transmission customers in the ATSI zone.

On February 1, 2011, ATSI in conjunction with PJM filed its proposal with FERC for moving its transmission rate into PJM's tariffs. On April 1, 2011, the MISO TOs (including ATSI) filed proposed tariff language that describes the mechanics of collecting and administering MTEP costs from ATSI-zone ratepayers. From March 20, 2011 through April 1, 2011, FirstEnergy, PJM and the MISO submitted numerous filings for the purpose of effecting movement of the ATSI zone to PJM on June 1, 2011. These filings include amendments to the MISO's tariffs (to remove the ATSI zone), submission of load and generation interconnection agreements to reflect the move into PJM, and submission of changes to PJM's tariffs to support the move into PJM.

On May 31, 2011, FERC issued orders that address the proposed ATSI transmission rate, and certain parts of the MISO tariffs that reflect the mechanics of transmission cost allocation and collection. In its May 31, 2011 orders, FERC approved ATSI's proposal to move the ATSI formula rate into the PJM tariff without significant change. Speaking to ATSI's proposed treatment of the MISO's exit fees and charges for transmission costs that were allocated to the ATSI zone, FERC required ATSI to present a cost-benefit study that demonstrates that the benefits of the move for transmission customers exceed the costs of any such move, which FERC had not previously required. Accordingly, FERC ruled that these costs must be removed from ATSI's proposed transmission rates until such time as ATSI files and FERC approves the cost-benefit study. On June 30, 2011, ATSI submitted the compliance filing that removed the MISO exit fees and transmission cost allocation charges from ATSI's proposed transmission rates. Also on June 30, 2011, ATSI requested rehearing of FERC's decision to require a cost-benefit analysis as part of FERC's evaluation of ATSI's proposed transmission rates. Finally, and also on June 30, 2011, the MISO and the MISO TOs filed a competing compliance filing - one that would require ATSI to pay certain charges related to construction and operation of transmission projects within the MISO even though FERC ruled that ATSI cannot pass these costs on to ATSI's customers. ATSI on the one hand, and the MISO and MISO TOs on the other, have submitted subsequent filings - each of which is intended to refute the other's claims. ATSI's compliance filing and request for rehearing, as well as the pleadings that reflect the dispute between ATSI and the MISO/MISO TOs, are currently pending before FERC.

From late April 2011 through June 2011, FERC issued other orders that address ATSI's move into PJM. Also, ATSI and the MISO were able to negotiate an agreement of ATSI's responsibility for certain charges associated with long term firm transmission rights that, according to the MISO, were payable by the ATSI zone upon its departure from the MISO. ATSI did not and does not agree that these costs should be charged to ATSI but, in order to settle the case and all claims associated with the case, ATSI agreed to a one-time payment of$1.8 millionto the MISO. This settlement agreement has been submitted for FERC's review and approval. The final outcome of those proceedings that address the remaining open issues related to ATSI's move into PJM and their impact, if any, on FirstEnergy cannot be predicted at this time.

MISO Multi-Value Project Rule Proposal

In July 2010, MISO and certain MISO transmission owners jointly filed with FERC their proposed cost allocation methodology for certain new transmission projects. The new transmission projects--described as MVPs - are a class of transmission projects that are approved via the MTEP. The filing parties proposed to allocate the costs of MVPs by means of a usage-based charge that will be applied to all loads within the MISO footprint, and to energy transactions that call for power to be recovered“wheeled through” the MISO as well as to energy transactions that “source” in the MISO but “sink” outside of MISO. The filing parties expect that the MVP proposal will fund the costs of large transmission projects designed to bring wind generation from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressingupper Midwest to load centers


10


in the east. The filing parties requested an effective date for the proposal of July 16, 2011. On August 19, 2010, MISO's Board approved the first MVP project -- the “Michigan Thumb Project.” Under MISO's proposal, the costs of MVP projects approved by MISO's Board prior to the June 1, 2011 effective date of FirstEnergy's integration into PJM would continue to be allocated to FirstEnergy. MISO estimated that approximately$15 millionin annual revenue requirements would be allocated to the ATSI zone associated with the Michigan Thumb Project upon its completion.

In September 2010, FirstEnergy filed a protest to the MVP proposal arguing that MISO's proposal to allocate costs of MVPs projects across the entire MISO footprint does not align with the established rule that cost allocation is to be based on cost causation (the “beneficiary pays” methodology for below 500 kV facilities, but excludingapproach). FirstEnergy also argued that, in light of progress that had been made to date in the issue of allocating new facilitiesATSI integration into PJM, it would be unjust and unreasonable to allocate any MVP costs to merchant transmission entities, wasthe ATSI zone, or to ATSI. Numerous other parties filed pleadings 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, theMISO's MVP proposal.

In December 2010, FERC issued an order conditionally approving the settlement. 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 accordanceMVP proposal without significant change. Despite being presented with the settlement. The remaining merchant transmission cost allocation issues wereissue by FirstEnergy and the subject of a hearing atMISO, the FERC did not address clearly the question of whether the MVP costs would be payable by ATSI or load in May 2008. the ATSI zone. FERC stated that the MISO's tariffs obligate ATSI to pay all charges that attached prior to ATSI's exit but ruled that the question of the amount of costs that are to be allocated to ATSI or to load in the ATSI zone were beyond the scope of FERC's order and would be addressed in future proceedings.

On November 19, 2009,January 18, 2011, FirstEnergy requested rehearing of FERC's order. In its rehearing request, FirstEnergy argued that because the MVP rate is usage-based, costs could not be applied to ATSI, which is a stand-alone transmission company that does not use the transmission system. FirstEnergy also renewed its arguments regarding cost causation and the impropriety of allocating costs to the ATSI zone or to ATSI.On October 21, 2011, FERC issued Opinion 503 agreeingits order on rehearing, but that RTEP costs should be allocatedorder did not address FirstEnergy's argument directly. FERC ruled instead that if ATSI was subject to MVP charges then ATSI owed these charges upon exit of the MISO. On October 31, 2011, FESC filed a Petition of Review for the FERC's December 2010 order and October 21, 2011 order on rehearing of that order with the U.S. Court of Appeals for the D.C. Circuit. Other parties also filed appeals of those orders and, in November, 2011, the cases were consolidated for briefing and disposition in the U.S. Court of Appeals for the Seventh Circuit. On January 27, 2012, the court ordered the FERC to file a pro-rata basisproposed briefing format and schedule on or before March 20, 2012.

On August 3, 2011, FirstEnergy filed a complaint with FERC based on the FERC's December 2010 order. In the complaint, FirstEnergy argued that ATSI perfected the legal and financial requirements necessary to merchant transmission companies.exit MISO before any MVP responsibilities could attach and asked FERC to rule that MISO cannot charge ATSI for MVP costs. On September 2, 2011, MISO, its TOs and other parties, filed responsive pleadings. On September 19, 2011, ATSI filed an answer. On December 22, 2009,29, 2011, the MISO and the MISO TOs filed a requestnew “Schedule 39” to the MISO's tariff. Schedule 39 purports to establish a process whereby the MISO would bill TOs for a rehearing of FERC’s Opinion No. 503 was made.MVP costs that, according to the MISO, attached to the utility prior to such TOs withdrawal from the MISO. On January 19, 2010,2012, FirstEnergy filed a protest to the MISO's new Schedule 39 tariff.

On February 27, 2012, FERC issued an order (February 2012 Order) dismissing ATSI's August 3, 2011 complaint. In the February 2012 Order, FERC accepted the MISO's Schedule 39 tariff, subject to hearings and potential refund of MVP charges to ATSI. The basis for any subsequent hearing is whether the Schedule 39 tariff was in effect at the time that ATSI exited the MISO. FirstEnergy is evaluating the February 2012 Order and will determine the next steps.

FirstEnergy cannot predict the outcome of these proceedings or estimate the possible loss or range of loss.

FirstEnergy Companies' PJM FTR Contract Underfunding Complaint

On December 28, 2011, FES and AE Supply filed a proceduralcomplaint with FERC against PJM challenging the ongoing underfunding of FTR contracts, which exist to hedge against transmission congestion in the day-ahead markets. The underfunding is a result of PJM's practice of using the funds that are intended to pay the holders of FTR contracts to pay instead for congestion costs that occur in the real time markets. Underfunding of the FTR contracts resulted in losses of approximately$35 millionto FES and AE Supply in the 2010-2011 Delivery Year. To date, losses for the 2011-2012 Delivery Year are estimated to be approximately$6 million.

On January 13, 2012, PJM filed comments that describe changes to the PJM tariff that, if adopted, should remedy the underfunding issue. Many parties also filed comments supporting FES' and AE Supply's position. Other parties, generally representatives of end-use customers who will have to pay the charges, filed in opposition to the complaint. The matter is currently pending before FERC. FirstEnergy cannot predict the outcome of this matter or estimate the possible loss or range of loss.
California Claims Matters

In October 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the CDWR during 2001. The settlement proposal claims that CDWR is owed approximately$190 millionfor these alleged overcharges. This proposal was made in the context of mediation efforts by FERC and the United States Court of Appeals for the Ninth Circuit in pending proceedings to resolve all outstanding refund and other claims, including claims of alleged price manipulation in the California energy markets during 2000 and 2001. The Ninth Circuit has since remandedoneof those proceedings to FERC, which arises out of claims previously filed with FERC by the California Attorney General on behalf of certain California parties against various sellers


11


in the California wholesale power market, including AE Supply (the Lockyer case). AE Supply and several other sellers filed motions to dismiss the Lockyer case. In March 2010, the judge assigned to the case entered an opinion that granted the motions to dismiss filed by AE Supply and other sellers and dismissed the claims of the California Parties. On May 4, 2011, FERC affirmed the judge's ruling. On June 3, 2011, the California parties requested rehearing of the May 4, 2011 order. The request for rehearing remains pending.

In June 2009, the California Attorney General, on behalf of certain California parties, filed a second complaint with FERC against various sellers, including AE Supply (the Brown case), again seeking refunds for trades in the California energy markets during 2000 and 2001. The above-noted trades with CDWR are the basis for including AE Supply in this new complaint. AE Supply filed a motion to dismiss the Brown complaint that was granted by FERC on May 24, 2011. On June 23, 2011, the California Attorney General requested rehearing of the May 24, 2011 order. That request for rehearing also remains pending. FirstEnergy cannot predict the outcome of either of the above matters or estimate the possible loss or range of loss.

PATH Transmission Project

The PATH Project is comprised of a765kV transmission line that was proposed to extend from West Virginia through Virginia and into Maryland, modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland.

PJM initially authorized construction of the PATH Project in June 2007. In December 2010, PJM advised that its 2011 Load Forecast Report included load projections that are different from previous forecasts and that may have an impact on the proposed in-service date for the PATH Project. As part of its 2011 RTEP, and in response to a January 19, 2011, directive by a Virginia Hearing Examiner, PJM conducted a series of analyses using the most current economic forecasts and demand response commitments, as well as potential new generation resources. Preliminary analysis revealed the expected reliability violations that necessitated the PATH Project had moved several years into the future. Based on those results, PJM announced on February 28, 2011, that its Board of Managers had decided to hold the PATH Project in abeyance in its 2011 RTEP and directed FirstEnergy and AEP, as the sponsoring transmission owners, to suspend current development efforts on the project, subject to those activities necessary to maintain the project in its current state, while PJM conducts more rigorous analysis of the need for the project as part of its continuing RTEP process. PJM stated that its action did not constitute a directive to FirstEnergy and AEP to cancel or abandon the PATH Project. PJM further stated that it will complete a more rigorous analysis of the PATH Project and other transmission requirements and its Board will review this comprehensive analysis as part of its consideration of the 2011 RTEP. On February 28, 2011, affiliates of FirstEnergy and AEP filed motions or notices to withdraw applications for authorization to construct the project that were pending before state commissions in West Virginia, Virginia and Maryland. Withdrawal was deemed effective upon filing the notice with the MDPSC. The WVPSC and VSCC have granted the motions to withdraw.

PATH submitted a filing to FERC to implement a formula rate tariff effective March 1, 2008. In a November 19, 2010 order noting thataddressing various matters relating to the formula rate, FERC would addressset the rehearing requestsproject's base ROE for hearing and reaffirmed its prior authorization of a return on CWIP, recovery of start-up costs and recovery of abandonment costs. In the order, FERC also granted a1.5%ROE incentive adder and a0.5%ROE adder for RTO participation. These adders will be applied to the base ROE determined as a result of the hearing. The PATH Companies, Joint Intervenors, Joint Consumer Advocates and FERC staff have agreed to a four year moratorium. A settlement was reached, which reflects a base ROE of10.4%(plus authorized adders) effective January 1, 2011. Accordingly, the revised ROE was reflected in a revised Projected Transmission Revenue Requirement for 2011 with true-up occurring in 2013. The FirstEnergy portion of the refund for March 1, 2008, through December 31, 2010, is approximately$2 million(inclusive of interest). The refund amount was computed using a base ROE of10.8%plus authorized adders. On October 7, 2011, PATH and six intervenors submitted to FERC an unopposed settlement agreement. Contemporaneous with this submission, PATH and the six intervenors filed with the Chief ALJ of FERC a joint motion for interim approval and authorization to implement the refund on an interim basis pending issuance of a FERC order acting on the settlement agreement. On October 12, 2011, the motion for interim approval and authorization to implement the refund was granted by the Chief ALJ. On February 16, 2012, FERC approved the settlement agreement and dismissed as moot, in light of its approval of the settlement, PATH's pending request for rehearing of the November 19, 2010 order.
Capital Requirements
Our capital spending for 2012 is expected to be approximately$2.1 billion(excluding nuclear fuel).For 2013, we anticipate baseline capital expenditures of approximately $2.0 billion, which exclude any potential additional strategic opportunities, future order.mandated spending, energy efficiency or environmental spending relating to MATS. Planned capital initiatives are intended to promote reliability, improve operations, and support current environmental and energy efficiency directives.Our capital investments for additional nuclear fuel are expected to be $280 million and $219 million in 2012 and 2013, respectively.
Anticipated capital expenditures for 2012, excluding nuclear fuel, are shown in the following table. Such costs include expenditures for the betterment of existing facilities and for the construction of transmission lines, distribution lines and substations, and other assets.


RTO Consolidation12


 
2011
Actual
 
Capital
Expenditures
Forecast 2012
 (In millions)
OE$178
 $167
Penn30
 21
CEI120
 110
TE47
 39
JCP&L327
 206
Met-Ed138
 105
Penelec159
 136
MP164
 142
PE96
 89
WP153
 128
ATSI113
 84
TrAIL82
 20
FGCO198
 131
NGC409
 452
AE Supply141
 144
Other subsidiaries128
 116
Total$2,483
 $2,090
During the 2012-2016 period, maturities of, and sinking fund requirements for long-term debt are:
 2012 2013-2016 Total
 (In millions)
FE$—
 $150
 $150
FES270
 1,758
 2,028
OE—
 400
 400
Penn1
 4
 5
CEI22
 381
 403
JCP&L34
 458
 492
Met-Ed—
 429
 429
Penelec—
 195
 195
Other(1)
637
 1,631
 2,268
Total$964
 $5,406
 $6,370
(1)
Includes debt of AE and its subsidiaries and the elimination of certain intercompany debt.
The following tables display consolidated operating lease commitments as of December 31, 2011.
  FirstEnergy  
Operating Leases Lease Payments 
Capital Trust(1)
 Net
  (In millions)
2012 $383
 $125
 $258
2013 382
 130
 252
2014 371
 131
 240
2015 373
 90
 283
2016 344
 29
 315
Years thereafter 1,803
 4
 1,799
Total minimum lease payments $3,656
 $509
 $3,147
(1)
PNBV and Shippingport purchased a portion of the lease obligation bonds associated with certain sale and leaseback transactions. These arrangements effectively reduce lease costs related to those transactions.



On August 17, 2009, 13


Operating Leases FES 
OE(1)
 CEI 
TE(1)
 JCP&L Met-Ed Penelec
  (In millions)
2012 $237
 $147
 $4
 $64
 $7
 $4
 $3
2013 241
 146
 3
 64
 7
 4
 3
2014 236
 145
 3
 64
 6
 3
 2
2015 239
 145
 2
 64
 5
 4
 2
2016 230
 117
 3
 64
 5
 3
 2
Years thereafter 1,662
 49
 4
 14
 48
 37
 12
Total minimum lease payments $2,845
 $749
 $19
 $334
 $78
 $55
 $24
(1)
Includes certain minimum lease payments associated with NGC's lessor equity interests in Perry and Beaver Valley Unit 2 that are eliminated in consolidation (see Note 6, Leases, of the Combined Notes to the Consolidated Financial Statements).
FirstEnergy filed an application with the FERC requestingexpects its existing sources of liquidity to consolidateremain sufficient to meet its transmission assetsanticipated obligations and operations into PJM. Currently,those of its subsidiaries. FirstEnergy’s transmission assetsbusiness is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. In addition to internal sources to fund liquidity and capital requirements for 2012 and beyond, FirstEnergy expects to rely on external sources of funds. Short-term cash requirements not met by cash provided from operations are divided between PJMgenerally satisfied through short-term borrowings. Long-term cash needs may be met through issuances of debt and/or equity securities. FirstEnergy expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements along with continued access to long-term capital markets.
FirstEnergy had no significant short-term debt outstanding as of December 31, 2011. Total short-term bank lines of committed credit to FirstEnergy totaled $5.0 billion. FirstEnergy’s available liquidity as of January 31, 2012, was as follows:
Company Type Maturity Commitment Available Liquidity
      (In millions)
FirstEnergy(1)
 Revolving June 2016 $2,000
 $1,395
FES / AE Supply Revolving June 2016 2,500
 2,498
TrAIL Revolving Jan. 2013 450
 450
AGC Revolving Dec. 2013 50
 —
    Subtotal $5,000
 $4,343
    Cash —
 49
    Total $5,000
 $4,392
(1)
FE and the Utilities
FirstEnergy and MISO.certain of its subsidiaries participate in two five-year syndicated revolving credit facilities with aggregate commitments of$4.5 billion(Facilities).
An aggregate amount of$2 billionis available to be borrowed under a syndicated revolving credit facility (FirstEnergy Facility), subject to separate borrowing sublimits for each borrower. The consolidation would makeborrowers under the transmission assetsFirstEnergy Facility are FE, OE, Penn, CEI, TE, Met-Ed, ATSI, JCP&L, MP, Penelec, PE and WP. An additional$2.5 billionis available to be borrowed by FES and AE Supply under a separate syndicated revolving credit facility (FES/AE Supply Facility), subject to separate borrowing sublimits for each borrower.
Commitments under each of the Facilities will be available until June 17, 2016, unless the lenders agree, at the request of the applicable borrowers, to up to two additional one-year extensions. Generally, borrowings under each of the Facilities are available to each borrower separately and mature on the earlier of364days from the date of borrowing or the commitment termination date, as the same may be extended.
Borrowings under each of the Facilities are subject to the usual and customary provisions for acceleration upon the occurrence of events of default, including a cross-default for other indebtedness in excess of$100 million, as described further in Note 12, Capitalization.
FirstEnergy also has established$500 millionof revolving credit facilities that are partavailable to TrAIL ($450 million) and AGC($50 million) until January 2013 and December 2013, respectively.
FE’s primary source of ATSI, whose footprint includescash for continuing operations as a holding company is cash from the operations of its subsidiaries. During 2011, FirstEnergy received $1.8 billion of cash dividends from its subsidiaries and paid$881 millionin cash dividends to common shareholders, including $20 million paid in March by AE to its former shareholders.


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As ofDecember 31, 2011, the Ohio Companies and Penn part had the aggregate capability to issue approximately$2.7 billionof PJM. Mostadditional FMBs on the basis of FirstEnergy’s transmission assets in Pennsylvaniaproperty additions and all of the transmission assets in New Jersey already operate as a part of PJM. Key elements of the filing include a “Fixed Resource Requirement Plan” (FRR Plan) that describes the means whereby capacity will be procured and administered as necessary to satisfy the PJM capacity requirements for the 2011-12 and 2012-13 delivery years; and also a request that ATSI’s transmission customers be excused from the costs for regional transmission projects that were approved through PJM’s RTEP process prior to ATSI’s entry into PJM (legacy RTEP costs). The integration is expected to be complete on June 1, 2011, to coincide with delivery of powerretired bonds under the next competitive generation procurement process for the Ohio Companies. 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 issueterms of exempting the ATSI footprint from the legacy RTEP costs.

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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 elementstheir respective mortgage indentures. The issuance 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.

On December 17, 2009, FERC issued an order approving, subject to certain future compliance filings, ATSI’s move to PJM. FirstEnergy’s request to be exempted from legacy RTEP costs was rejected and its complaint dismissed.

On December 17, 2009, ATSI executed the PJM Consolidated Transmission Owners Agreement. On December 18, 2009, 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 moving into PJM on the schedule described in the application and approved in the FERC Order (June 1, 2011).

On January 15, 2010, the Ohio Companies and Penn submitted a compliance filing describing the process whereby ATSI-zone load serving entities (LSEs) can “opt out” of the Ohio Companies' and Penn's FRR Plan for the 2011-12 and 2012-13 Delivery Years. On January 16, 2010, FirstEnergy filed for clarification or rehearing of certain issues associated with implementing the FRR auctions on the proposed schedule. On January 19, 2010, FirstEnergy filed for rehearing of FERC’s decision to impose the legacy RTEP costs on ATSI’s transmission customers. Also on January 19, 2010, several parties, including the PUCO and the OCC asked for rehearing of parts of FERC’s order. None of the rehearing parties asked FERC to rescind authorization for ATSI to enter PJM. Instead, parties focused on questions of cost and cost allocation or on alleged errors in implementing the move. On February 3, 2010, FirstEnergy filed an answer to the January 19, 2010 rehearing requests of other parties. On February 16, 2010, FirstEnergy submitted a second compliance filing to FERC; the filing describes communications protocols and performance deficiency penalties for capacity suppliers that are taken in FRR auctions.

FirstEnergy will conduct FRR auctions on March 15-19, 2010, for the 2011-12 and 2012-13 delivery years. LSE’s in the ATSI territory, including the Ohio Companies and Penn, will participate in PJM’s next base residual auction for capacity resources for the 2013-2014 delivery years.  This auction will be conducted in May of 2010. FirstEnergy expects to integrate into PJM effective June 1, 2011.

Changes ordered for PJM Reliability Pricing Model (RPM) Auction

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

On March 26, 2009, the FERC accepted in part, and rejected in part, tariff provisions submitted by PJM, revising certain parts of its RPM. It ordered changes included making incremental improvements to RPM and 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; 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. On December 1, 2009, PJM informed FERC that PJM would file a scarcity-pricing design with FERC on April 1, 2010.

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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. The FERC conditionally approved MISO’s Resource Adequacy proposal on March 26, 2008. 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 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 program was implemented as planned and became effective on June 1, 2009, the beginning of the MISO planning year. On June 17, 2009, MISO submitted a compliance filing in response to the FERC’s April 16, 2009 order directing it to address, among others, various market monitoring and mitigation issues. On July 8, 2009, various parties submitted comments on and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific aspects of the MISO’s and Independent Market Monitor’s proposals for market monitoring and mitigation and other issues that it believes the FERC should address and clarify. On October 23, 2009, FERC issued an order approving a MISO compliance filing that revised its tariff to provide for netting of demand resources, but prohibiting the netting of behind-the-meter generation.

FES Sales to Affiliates

FES supplied all of the power requirements for the Ohio Companies pursuant to a Power Supply Agreement that ended on December 31, 2008. On January 2, 2009, FES signed an agreement to provide 75% of the Ohio Companies’ power requirements for the period January 5, 2009 through March 31, 2009. Subsequently, FES signed an agreement to provide 100% of the Ohio Companies’ power requirements for the period April 1, 2009 through May 31, 2009. On March 4, 2009, the PUCO issued an order approving these two affiliate sales agreements. FERC authorization for these affiliate sales was by means of a December 23, 2008 waiver of restrictions on affiliate sales without prior approval of the FERC. Rehearing was denied on July 31, 2009. On October 19, 2009, FERC accepted FirstEnergy’s revised tariffs.

On May 13-14, 2009, FES participated in a descending clock auction for PLR service administeredFMBs 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 their consultant, CRA International. FES won 51 tranches in the auction, and entered intoCEI to incur additional secured debt not otherwise permitted by a Master SSO Supply Agreementspecified exception of up to provide capacity, energy, ancillary services $232 millionand transmission to the Ohio Companies for a two-year period beginning June 1, 2009. Other winning suppliers have assigned their Master SSO Supply Agreements to FES, five of which were effective in June, two more in July, four more in August and ten more in September, 2009. FES also supplies power used by Constellation to serve an additional five tranches.$20 million, respectively. As a result of the indenture provisions, TE cannot incur any additional secured debt. Met-Ed and Penelec had the capability to issue secured debt of approximately$376 millionand$382 million, respectively, under provisions of their senior note indentures as ofDecember 31, 2011. In addition, based upon their respective FMB indentures, net earnings and available bondable property additions as ofDecember 31, 2011, MP, PE and WP had the capability to issue approximately$1.1 billionof additional FMBs in the aggregate. These companies may be further limited by the financial covenants of the Facilities and subject to current regulatory approvals and applicable statutory and/or charter limitations.
Based upon FGCO’s net earnings and available bondable property additions under its FMB indentures as ofDecember 31, 2011, FGCO had the capability to issue$2.1 billionof additional FMBs under the terms of that indenture. Based upon NGC’s net earnings and available bondable property additions under its FMB indenture as ofDecember 31, 2011, NGC had the capability to issue$2.0 billionof additional FMBs under the terms of that indenture.
To the extent that coverage requirements or market conditions restrict the subsidiaries’ abilities to issue desired amounts of FMBs or preferred stock, they may seek other methods of financing. Such financings could include the sale of preferred and/or preference stock or of such other types of securities as might be authorized by applicable regulatory authorities which would not otherwise be sold. These financings could result in annual interest charges and/or dividend requirements in excess of those that would otherwise be incurred.
Nuclear Operating Licenses
In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse operating license for an additional twenty years, until 2037. By an order dated April 26, 2011, a NRC ASLB granted a hearing on the Davis-Besse license renewal application to a group of petitioners. By this order, the ASLB also admitted two contentions challenging whether FENOC's Environmental Report adequately evaluated (1) a combination of renewable energy sources as alternatives to the renewal of Davis-Besse's operating license, and (2) severe accident mitigation alternatives at Davis-Besse. On May 6, 2011, FENOC filed an appeal with the NRC from the order granting a hearing on the Davis-Besse license renewal application.On January 10, 2012, intervenors petitioned the ASLB for a new contention on the cracking of the Davis-Besse shield building discussed below.
The following table summarizes the current operating license expiration dates for FES' nuclear facilities in service.
Station In-Service Date Current License Expiration
Beaver Valley Unit 1 1976 2036
Beaver Valley Unit 2 1987 2047
Perry 1986 2026
Davis-Besse 1977 2017
Nuclear Regulation
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As ofDecember 31, 2011, FirstEnergy had approximately$2 billioninvested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy's NDT fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy's obligation to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the NDT. On March 28, 2011, FENOC submitted its biennial report on nuclear decommissioning funding to the NRC. This submittal identified a total shortfall in nuclear decommissioning funding for Beaver Valley Unit 1 and Perry of approximately$92.5 million. By letter dated December 29, 2011, FENOC informed the NRC staff that it had increased the parental guarantee to$95 million.
In January 2004, subsidiaries of FirstEnergy filed a lawsuit in the U.S. Court of Federal Claims seeking damages in connection with costs incurred at the Beaver Valley, Davis-Besse and Perry nuclear facilities as a result of the DOE's failure to begin accepting spent nuclear fuel on January 31, 1998. DOE was required to begin accepting spent nuclear fuel by the Nuclear Waste Policy Act (42 USC 10101 et seq) and the contracts entered into by the DOE and the owners and operators of these facilities pursuant to the Act.In January 2012, the applicable FirstEnergy affiliates reached a$48 millionsettlement of these claims.
On October 1, 2011, Davis-Besse was safely shut down for a scheduled outage to install a new reactor vessel head and complete other maintenance activities. The new reactor head, which replaced a head installed in 2002, enhances safety and reliability, and features control rod nozzles made of material less susceptible to cracking. On October 10, 2011, following opening of the building


15


for installation of the new reactor head, a sub-surface hairline crack was identified in one of the exterior architectural elements on the shield building. These elements serve as architectural features and do not have structural significance. During investigation of the crack at the shield building opening, concrete samples and electronic testing found similar sub-surface hairline cracks in most of the building's architectural elements. FENOC's investigation also identified other indications. Included among them were sub-surface hairline cracks in the upper portion of the shield building (above elevation 780') and in the vicinity of the main steam line penetrations.A team of industry-recognized structural concrete experts and Davis-Besse engineers has determined these conditions do not affect the facility's structural integrity or safety.
On December 2, 2011, the NRC issued a CAL which concluded that FENOC provided "reasonable assurance that the shield building remains capable of performing its safety functions." The CAL imposed a number of commitments from FENOC including, submitting a root cause evaluation and corrective actions to the NRC by February 28, 2012, and further evaluations of the shield building. On February 27, 2012, FENOC sent the root cause evaluation to the NRC. Finally, the CAL also stated that the NRC was still evaluating whether the current condition of the shield building conforms to the plant's licensing basis. On December 6, 2011, the Davis-Besse plant returned to service.
By letter dated August 25, 2011, the NRC made a final significance determination (white) associated with a violation that occurred during the retraction of a source range monitor from the Perry reactor vessel. The NRC also placed Perry in the degraded cornerstone column (Column 3) of the NRC's Action Matrix governing the oversight of commercial nuclear reactors. As a result, the NRC staff will conduct several supplemental inspections, culminating in an inspection using Inspection Procedure 95002 to determine if the root cause and contributing causes of risk significant performance issues are understood, the extent of condition has been identified, whether safety culture contributed to the performance issues, and if FENOC's corrective actions are sufficient to address the causes and prevent recurrence.
In light of the impacts of the earthquake and tsunami on the reactors in Fukushima, Japan, the NRC conducted inspections of emergency equipment at U.S. reactors. The NRC also established a Near-Term Task Force to review its processes and regulations in light of the incident, and, on July 12, 2011, the Task Force issued its report of recommendations for regulatory changes. On October 18, 2011, the NRC approved the Staff recommendations, and directed the Staff to implement its near-term recommendations without delay. Ultimately, the adoption of the Staff recommendations on near-term actions is likely to result in additional costs to implement plant modifications and upgrades required by the regulatory process over the next several years, which costs are likely to be material.

On February 16, 2012, the NRC issued a request for information to the licensed operators of 11 nuclear power plants, including Beaver Valley Power Station Units 1 and 2, with respect to the modeling of fuel performance as it relates to "thermal conductivity degradation," which is the potential in older fuel for reduced capacity to transfer heat that could potentially change its performance during various accident scenarios, including loss of coolant accidents. The request for information indicated that this phenomenon has not been accounted for adequately in performance models for the fuel developed by the fuel manufacturer. The NRC is requesting that FENOC provide an analysis to demonstrate that the NRC regulations are being met. Absent that demonstration, the request indicates that the NRC may consider imposing restrictions on reactor operating limits until the issue is satisfactorily resolved.
Nuclear Insurance
The Price-Anderson Act limits the public liability which can be assessed with respect to a nuclear power plant to $12.6 billion (assuming 104 units licensed to operate) for a single nuclear incident, which amount is covered by: (i) private insurance amounting to $375 million; and (ii) $12.2 billion provided by an industry retrospective rating plan required by the NRC pursuant thereto. Under such retrospective rating plan, in the event of a nuclear incident at any unit in the United States resulting in losses in excess of private insurance, up to $118 million (but not more than $18 million per unit per year in the event of more than one incident) must be contributed for each nuclear unit licensed to operate in the country by the licensees thereof to cover liabilities arising out of the incident. Based on their present nuclear ownership and leasehold interests, FirstEnergy’s maximum potential assessment under these provisions would be $470 million (OE-$40 million, NGC-$408 million, and TE-$22 million) per incident but not more than $70 million (OE-$6 million, NGC-$61 million, and TE-$3 million) in any one year for each incident.
In addition to the public liability insurance provided pursuant to the Price-Anderson Act, FirstEnergy has also obtained insurance coverage in limited amounts for economic loss and property damage arising out of nuclear incidents. FirstEnergy is a member of NEIL, which provides coverage (NEIL I) for the extra expense of replacement power incurred due to prolonged accidental outages of nuclear units. Under NEIL I, FirstEnergy’s subsidiaries have policies, renewable yearly, corresponding to their respective nuclear interests, which provide an aggregate indemnity of up to approximately $2.0 billion (OE-$168 million, NGC-$1.7 billion, TE-$90 million) for replacement power costs incurred during an outage after an initial 26-week waiting period. Members of NEIL I pay annual premiums and are subject to assessments if losses exceed the accumulated funds available to the insurer. FirstEnergy’s present maximum aggregate assessment for incidents at any covered nuclear facility occurring during a policy year would be approximately $13 million (OE-$1 million, NGC-$12 million, and TE-less than $1 million).
FirstEnergy is insured as to its respective nuclear interests under property damage insurance provided by NEIL to the operating company for each plant. Under these arrangements, FES serves 77 tranches, up to $2.8 billion of coverage for decontamination costs, decommissioning costs, debris removal and repair and/or 77%replacement of property is provided. FirstEnergy pays annual premiums for this coverage and is liable for retrospective assessments of up to approximately $66 million (OE-$6 million, NGC-$57 million, TE-$2 million, Met


16


Ed, Penelec, and JCP&L-less than $1 million each) during a policy year.
FirstEnergy intends to maintain insurance against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of FirstEnergy’s plants exceed the policy limits of the PLR loadinsurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by FirstEnergy’s insurance policies, or to the extent such insurance becomes unavailable in the future, FirstEnergy would remain at risk for such costs.
The NRC requires nuclear power plant licensees to obtain minimum property insurance coverage of $1.1 billion or the amount generally available from private sources, whichever is less. The proceeds of this insurance are required to be used first to ensure that the licensed reactor is in a safe and stable condition and can be maintained in that condition so as to prevent any significant risk to the public health and safety. Within 30 days of stabilization, the licensee is required to prepare and submit to the NRC a cleanup plan for approval. The plan is required to identify all cleanup operations necessary to decontaminate the reactor sufficiently to permit the resumption of operations or to commence decommissioning. Any property insurance proceeds not already expended to place the reactor in a safe and stable condition must be used first to complete those decontamination operations that are ordered by the NRC. FirstEnergy is unable to predict what effect these requirements may have on the availability of insurance proceeds.
Hydro Relicensing
Yards Creek
The Yards Creek Pumped Storage Project is a400MW hydroelectric project located in Warren County, New Jersey. JCP&L owns an undivided50%interest in the project, and operates the project. PSEG Fossil, LLC, a subsidiary of Public Service Enterprise Group, owns the remaining interest in the plant. The project was constructed in the early 1960s, and became operational in 1965. Authorization to operate the project is by a license issued by the FERC. The existing license expires on February 28, 2013.

In February 2011, JCP&L and PSEG filed a joint application with FERC to renew the license for an additional forty years. The companies are pursuing relicensure through FERC's ILP. Under the ILP, FERC will assess the license applications, issue draft and final Environmental Assessments/Environmental Impact Studies (as required by NEPA), and provide opportunities for intervention and protests by affected third parties. FERC may hold hearings during the two-year ILP licensure period. FirstEnergy expects FERC to issue the new license within the remaining portion of the Ohio Companies.two-year ILP period. To the extent, however, that the license proceedings extend beyond the February 28, 2013 expiration date for the current license, the current license will be extended yearly as necessary to permit FERC to issue the new license.
Seneca

The Seneca Pumped Storage Project is a451MW hydroelectric project located in Warren County, Pennsylvania owned and operated by FGCO. FGCO holds the current FERC license that authorizes ownership and operation of the project. The current FERC license will expire on November 30, 2015. FERC's regulations call for a five-year relicensing process. On November 24, 2010, and acting pursuant to applicable FERC regulations and rules, FGCO initiated the relicensing process by filing its notice of intent to relicense and PAD in the license docket.

On November 3, 2009, FES, Met-Ed, Penelec30, 2010, the Seneca Nation filed its notice of intent to relicense and Waverly restated their partial requirements power purchase agreementPADs necessary for 2010. them to submit a competing application. Section 15 of the FPA contemplates that third parties may file a "competing application" to assume ownership and operation of a hydroelectric facility upon (i) relicensure and (ii) payment of net book value of the plant to the original owner/operator. Nonetheless, FGCO believes it is entitled to a statutory “incumbent preference” under Section 15.

The Fourth Restated Partial Requirements Agreement (PRA) continuesSeneca Nation and certain other intervenors have asked FERC to limitredefine the amount“project boundary” of capacity resources requiredthe hydroelectric plant to be suppliedinclude the dam and reservoir facilities operated by FESthe U.S. Army Corps of Engineers. On May 16, 2011, FirstEnergy filed a Petition for Declaratory Order with FERC seeking an order to 3,544 MW, but requires FES to supply essentially all of Met-Ed, Penelec,exclude the dam and Waverly’s energy requirements in 2010. Under the Fourth Restated Partial Requirements Agreement, Met-Ed, Penelec, and Waverly (Buyers) assigned 1,300 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 powerreservoir facilities from the third party intoproject. The Seneca Nation, the market or use it to serve the Met-Ed/Penelec load. FES is responsible for obtaining additional power supplies in the eventNew York State Department of failure of supply of the assigned energy purchase contracts. Prices for the power sold by FES under the Fourth Restated Partial Requirements Agreement 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, respectively, 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.

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Reliability Initiatives

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

FirstEnergy believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, it is clear that the NERC, ReliabilityFirstEnvironmental Conservation, and the FERC will continueU.S. Department of Interior each submitted responses to refine existing reliability standards as well asFirstEnergy's petition, including motions to develop and adopt new reliability standards.dismiss FirstEnergy's petition. The financial impact of complying with new or amended standards cannot be determined at this time. However, the 2005 amendments to the Federal Power Act provide that all prudent costs incurred to comply with the new reliability standards be recovered in rates. Still, any future inability on FirstEnergy’s part to comply with the reliability standards for its bulk power system could result in the imposition of financial penalties that 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 Midwest ISO 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 a final report“project boundary” issue is expected in early 2009. FirstEnergy does not expect any material adverse financial impact as a result of these audits.

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

On June 5, 2009,September 12, 2011, FirstEnergy self-reported to ReliabilityFirst a potential violation of NERC Standard PRC-005 resulting from its inability to validate maintenance records for 20 protection system relays (out of approximately 20,000 reportable relays) in JCP&L’s and Penelec’s transmission systems.the Seneca Nation each filed “Revised Study Plan” documents. 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 recordsdocuments describe the parties' respective proposals for the relays. ReliabilityFirstscope of the environmental studies that should be performed as part of the relicensing process. On October 11, 2011, FERC Staff issued an Initial Noticea letter order that addressed the Revised Study Plans. In the order, FERC Staff approved FirstEnergy's Revised Study Plan, subject to a finding that the Project is located on “aboriginal lands” of Alleged Violationthe Seneca Nation. Based on June 22, 2009. The NERC approved FirstEnergy’s mitigation plan on August 19, 2009,this finding, FERC Staff directed FirstEnergy to consult with the Seneca Nation and submitted it toother parties about the FERC for approval on August 19, 2009.data set, methodology, and modeling of the hydrological impacts of project operations. FirstEnergy is not able at this timeperforming the work necessary to predict what actions or penalties, if any, that ReliabilityFirstdevelop a study proposal from which to conduct such consultations. The study process will propose for this self-reported violation.extend through approximately November of 2013.

ENVIRONMENTAL MATTERSFirstEnergy cannot predict the outcome of this matter or estimate the possible loss or range of loss.


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Environmental Matters
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. The effects of compliance on FirstEnergyCompliance with regard to environmental mattersregulations could have a material adverse effect on FirstEnergy'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 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 ActCAA Compliance

FirstEnergy is required to meet federally-approved SO2 and NOx emissions regulations.regulations under the CAA. FirstEnergy complies with SO2and NOx reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, combustion controls and post-combustion controls, generating more electricity from lower or non-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 SO2penalties. regulations in Ohio that allows for compliance based on a 30-day averaging period. FirstEnergy believes it is currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.

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

In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W. H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case and seven other similar cases are referred to as the NSR cases. OE’s and Penn’s settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation was approved by the Court on July 11, 2005. This settlement agreement, in the form of a consent decree, requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices or repowering and provides for stipulated penalties for failure to install and operate such pollution controls or complete repowering in accordance with that agreement. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree, including repowering Burger Units 4 and 5 for biomass fuel consumption, are currently estimated to be $399 million for 2010-2012.

In October 2007, PennFuture and three of its members filed a citizen suit under the federal CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations, in the United States District Court for the Western District of Pennsylvania. In July 2008,three additional complaints were filed against FGCO in the U.S. District Court for the Western District of Pennsylvania seeking damages based on air emissions from the coal-fired Bruce Mansfield Plant air emissions. In addition to seeking damages, two Plant.Twoof the threethese complaints also seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”,manner,” one being a complaint filed on behalf oftwenty-oneindividuals and the other being a class action complaint seeking certification as a class action with theeightnamed plaintiffs as the class representatives. On October 16, 2009, a settlement reached with PennFuture and one of the three individual complainants was approved by the Court, which dismissed the claims of PennFuture and of the settling individual. The other two non-settling individuals are now represented by counsel handling the three cases filed in July 2008. FGCO believes thosethe claims are without merit and intends to defend itself against the allegations made in those threethese 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.

In December 2007, the statestates of New Jersey and Connecticut filed a CAA citizen suitsuits in 2007 alleging NSR violations at the coal-fired Portland Generation Station against Reliant (theGenOn Energy, Inc. (formerly RRI Energy, Inc. and the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU 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 underin violation of the CAA'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. Met-Ed filed a Motion to DismissIn September 2009, the claims in New Jersey’s Amended Complaint and Connecticut’s Complaint in February and September of 2009, respectively. The Court granted Met-Ed's motion to dismiss New Jersey’sJersey's and Connecticut’sConnecticut's claims for injunctive relief against Met-Ed, but denied Met-Ed’sMet-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 allowand from Sithe Energy, and Met-Ed is unable to predict the states to prove either thatoutcome of this matter or estimate the applicationpossible loss or range of the discovery rule or the doctrine of equitable tolling bars application of the statute of limitations.loss.
In January 2009, the EPA issued a NOV to ReliantGenOn Energy, Inc. alleging NSR violations at the coal-fired 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 2009, NOV also alleged NSR violations at the Keystone and Shawville Stationscoal-fired plants 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.matter or estimate the possible loss or range of loss.
In each of May and September 2010, New Jersey submitted interstate pollution transport petitions seeking to reduce Portland Generating Station air emissions under section 126 of the CAA. Based on the September 2010 petition, the EPA has finalized emissions limits and compliance schedules to reduce SO2air emissions by approximately 81% at the Portland Station by January 6, 2015. New Jersey's May 2010 petition is still under consideration by the EPA.
In June 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. alleging that "modifications"“modifications” at the coal-fired Homer City Power StationPlant occurred sincefrom 1988 to the present without preconstruction NSR or permitting underin violation of the CAA's PSD program. In May 2010, the EPA issued a second NOV to Mission, Energy isPenelec, NYSEG and others that have had an ownership interest in Homer City containing in all material respects allegations identical to those included in the June 2008 NOV. In January 2011, the DOJ filed a complaint against Penelec in the U.S. District Court for the Western District of Pennsylvania seeking indemnification frominjunctive relief against Penelec based on alleged “modifications” at Homer City between 1991 to 1994 without preconstruction NSR permitting in violation of the CAA's PSD and Title V permitting programs. The complaint was also filed against the former co-owner, (along withNYSEG, and various current owners of Homer City, including EME Homer City Generation L.P. and affiliated companies, including Edison International. In addition, the Commonwealth of Pennsylvania and the States of New Jersey and New York State Electricintervened and Gas Company)have filed separate complaints regarding Homer City seeking injunctive relief and operatorcivil penalties. In January 2011, another complaint was filed against Penelec and the other entities described above in the U.S. District Court for the Western District of Pennsylvania seeking damages based on Homer City's air emissions as well as certification as a class action and to enjoin Homer City from operating except in a “safe, responsible, prudent and proper manner.” In October 2011, the Court dismissed all of the Homer City Power Station priorclaims with prejudice of the U.S. and the Commonwealth of Pennsylvania and the States of New Jersey and New York and all of the claims of the private parties, without prejudice to its salere-file state law claims in 1999. The scopestate court, against all of Penelec’s indemnity obligationthe defendants, including Penelec.In December 2011, the U.S., the Commonwealth of Pennsylvania and the States of New Jersey and New York all filed notices appealing to the Third Circuit Court of Appeals. Penelec believes the claims are without merit and from Mission Energy is disputed. Penelecintends to defend itself against the allegations made in these complaints, but, at this time, is unable to predict the outcome of this matter.

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matter or estimate the loss or possible range of loss. Mission is seeking indemnification from NYSEG and Penelec, the co-owners of Homer City prior to its sale in 1999. On February 13, 2012, the Sierra Club notified the current owner and operator of Homer City, Homer City OL1-OL8 LLC and EME Homer City Generation L.P., that it intends to file a CAA citizen suit regarding its Title V permit and SO2emissions from the Homer City Plant.
In August 2009, the EPA issued a Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, including the PSD, NNSR and Title V regulations, at the Eastlake, Lakeshore, Bay Shore and Ashtabula generatingcoal-fired plants. The EPA’sEPA'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. In September 2009, FGCO also received an informationa request pursuant to Section 114(a) of the CAA requestingfor certain operating and maintenance information and planning


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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 plantPlant may constitute a major modification under the NSR provisionprovisions of the CAA. On December 23,Later in 2009, FGCO also received another information request regarding emission projections for the Eastlake generating plantPlant. In June 2011, EPA issued another Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, specifically opacity limitations and requirements to continuously operate opacity monitoring systems at the Eastlake, Lakeshore, Bay Shore and Ashtabula coal-fired plants. Also, in June 2011, FirstEnergy received an information request pursuant to Sectionsection 114(a) of the CAA.CAA for certain operating, maintenance and planning information, among other information regarding these plants. FGCO intends to comply with the CAA, including EPA’sthe EPA's information requests but, at this time, is unable to predict the outcome of this matter. A June 2006 findingmatter or estimate the possible loss or range 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.loss.

In August 2008, FirstEnergy2000, AE received aan information request from the EPA for information pursuant to Sectionsection 114(a) of the CAA for certain operatingfrom the EPA requesting that it provide information and documentation relevant to the operation and maintenance information regarding its formerly-owned Avon Lakeof the followingtencoal-fired plants, which collectively include22electric generation units: Albright, Armstrong, Fort Martin, Harrison, Hatfield's Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Niles generating plants, as well as a copy of a nearly identical request directed to the current owner, Reliant Energy, to allow the EPAWillow Island to determine whether these generating sources are complyingcompliance with the NSR provisions under the CAA, which can require the installation of the CAA. FirstEnergy intendsadditional air emission control equipment when a major modification of an existing facility results in an increase in emissions. AE has provided responsive information to fully comply with the EPA’s informationthis and a subsequent request but at this time, is unable to predict the outcome of this matter.matter or estimate the possible loss or range of loss.
In May 2004, AE, AE Supply, MP and WP received a Notice of Intent to Sue Pursuant to CAA §7604 from the Attorneys General of New York, New Jersey and Connecticut and from the PA DEP, alleging that Allegheny performed major modifications in violation of the PSD provisions of the CAA at the following West Virginia coal-fired generation units: Albright Unit 3; Fort Martin Units 1 and 2; Harrison Units 1, 2 and 3; Pleasants Units 1 and 2 and Willow Island Unit 2. The Notice also alleged PSD violations at the Armstrong, Hatfield's Ferry and Mitchell coal-fired plants in Pennsylvania and identifies PA DEP as the lead agency regarding those facilities. In September 2004, AE, AE Supply, MP and WP received a separate Notice of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.
In June 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed suit against AE, AE Supply, MP, PE and WP in the United States District Court for the Western District of Pennsylvania alleging, among other things, that Allegheny performed major modifications in violation of the CAA and the Pennsylvania Air Pollution Control Act at the coal-fired Hatfield's Ferry, Armstrong and Mitchell Plants in Pennsylvania. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. A non-jury trial on liability only was held in September 2010. Plaintiffs filed their proposed findings of fact and conclusions of law in December 2010, Allegheny made its related filings in February 2011 and plaintiffs filed their responses in April 2011. The parties are awaiting a decision from the District Court, but there is no deadline for that decision and we are unable to predict the outcome or estimate the possible loss or range of loss.
In September 2007, Allegheny received a NOV from the EPA alleging NSR and PSD violations under the CAA, as well as Pennsylvania and West Virginia state laws at the coal-fired Hatfield's Ferry and Armstrong plants in Pennsylvania and the coal-fired Fort Martin and Willow Island plants in West Virginia.
FirstEnergy intends to vigorously defend against the CAA matters described above but cannot predict their outcomes or estimate the possible loss or range of loss.
State Air Quality Compliance
In early 2006, Maryland passed the Healthy Air Act, which imposes state-wide emission caps on SO2and NOx, requires mercury emission reductions and mandates that Maryland join the RGGI and participate in that coalition's regional efforts to reduce CO2emissions. On April 20, 2007, Maryland became the tenth state to join the RGGI. The Healthy Air Act provides a conditional exemption for the R. Paul Smith coal-fired plant for NOx, SO2and mercury, based on a 2006 PJM declaration that the plant is vital to reliability in the Baltimore/Washington DC metropolitan area. Pursuant to the legislation, the MDE passed alternate NOx and SO2limits for R. Paul Smith, which became effective in April 2009. However, R. Paul Smith is still required to meet the Healthy Air Act mercury reductions of80%which began in 2010. The statutory exemption does not extend to R. Paul Smith's CO2emissions. Maryland issued final regulations to implement RGGI requirements in February 2008.FourteenRGGI auctions have been held through the end of calendar year 2011. RGGI allowances are also readily available in the allowance markets, affording another mechanism by which to secure necessary allowances. On March 14, 2011, MDE requested PJM perform an analysis to determine if termination of operation at R. Paul Smith would adversely impact the reliability of electrical service in the PJM region under current system conditions. On June 30, 2011, PJM notified MDE that termination of operation at R. Paul Smith would adversely impact the reliability of electrical service in the PJM region absent transmission system upgrades. On January 26, 2012, FirstEnergy announced that R. Paul Smith is among nine coal-fired plants it intends to retire by September 1, 2012, subject to review of reliability impacts by PJM. FirstEnergy is unable to predict the outcome of this matter or estimate the possible loss or range of loss.
In January 2010, the WVDEP issued a NOV for opacity emissions at the Pleasants coal-fired plant. In August 2011, FirstEnergy and WVDEP resolved the NOV through a Consent Order requiring installation of a reagent injection system to reduce opacity by September 2012.
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 NOXNOx and SO2 emissions intwophases (Phase I in 2009 for NOX, (2009/2010 for SO2and Phase II in 2015 for both NOX and SO2)2015), ultimately capping SO2


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emissions in affected states to2.5 milliontons annually and NOXNOx emissions to1.3 milliontons annually. CAIR was challenged inIn 2008, the U.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.” In September 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. In December 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, 2008Court's opinion. On July 10, 2009, the U.S.The 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“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's future cost of compliance with these regulations may be substantial and will depend, in part, on the action taken by the EPA in response to the Court’s ruling.

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,July 2011, the EPA finalized the CAMR, which provides a cap-and-trade programCSAPR, to reduce mercury replace CAIR,requiring reductions of NOx and SO2emissions from coal-firedintwo phases (2012 and 2014), ultimately capping SO2emissions in affected states to2.4 milliontons annually and NOx emissions to1.2 milliontons annually. CSAPR allows trading of NOx and SO2emission allowances between power plants located in two phases; initially, capping national mercury the same state and interstate trading of NOx and SO2emission allowances with some restrictions. On February 21, 2012, the EPA revised certain CASPR state budgets (for Florida, Louisiana, Michigan, Mississippi, Nebraska, New Jersey, New York, Texas, and Wisconsin and new unit set-asides in Arkansas and Texas), certain generating unit allocations (for some units in Alabama, Indiana, Kansas, Kentucky, Ohio and Tennessee) for NOx and SO2emissions at 38 tonsand delayed from 2012 to 2014 certain allowance penalties that could apply with respect to interstate trading of NOx and SO2emission allowances.On December 30, 2011, CSAPR was stayed by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the U.S. Court of Appeals for the District of Columbia. Columbia Circuit pending a decision on legal challenges raised in appeals filed by various stakeholders and scheduled to be argued before the Court on April 13, 2012. The Court ordered EPA to continue administration of CAIR until the Court resolves the CSAPR appeals. Depending on the outcome of these proceedings and how any final rules are ultimately implemented, FGCO's and AE Supply's future cost of compliance may be substantial and changes to FirstEnergy's operations may result.

During 2011, FirstEnergy recorded pre-tax impairment charges of approximately$6 million($1 millionfor FES and$5 millionfor AE Supply) for NOx emission allowances that were expected to be obsolete after 2011 and approximately$21 million($18 millionfor FES and$3 millionfor AE Supply) for excess SO2emission allowances in inventory that it expects will not be consumed in the future.
Hazardous Air Pollutant Emissions
On December 21, 2011, the EPA finalized the MATS to establish emission standards for mercury, hydrochloric acid and various metals for electric generating units. The MATS establishes emission limits for mercury, PM, and HCL for all existing and new coal-fired electric generating units effective in April 2015 and allows averaging of emissions from multiple units located at a single plant. Under the CAA, state permitting authorities can grant an additional compliance year through April 2016, as needed, including instances when necessary to maintain reliability where electric generating units are being closed. In addition, an EPA enforcement policy document contemplates up to an additional year to achieve compliance, through April 2017, under certain circumstances for reliability critical units. On January 26, 2012 and February 8, 2008,2012, FGCO, MP and AE Supply announced the Court vacated the CAMR, ruling that the EPA failedretirement by September 1, 2012 (subject to take the necessary steps to “de-list”a reliability review by PJM) of nine coal-fired power plants from its hazardous air pollutant program(Albright, Armstrong, Ashtabula, Bay Shore except for generating unit 1, Eastlake, Lake Shore, R. Paul Smith, Rivesville and therefore, could not promulgateWillow Island) with a cap-and-trade program. The EPA petitioned for rehearingtotal capacity of3,349megawatts (generating, on average, approximately ten percent of the electricity produced by the entire Court, which deniedcompanies over the petition in May 2008. In October 2008, the EPA (and an industry group) petitioned the U.S. Supreme Court for review of the Court’s ruling vacating CAMR. On February 6, 2009, the EPA movedpast three years) due to dismiss its petition for certiorari. On February 23, 2009, the Supreme Court dismissed the EPA’s petition and denied the industry group’s petition. On October 21, 2009, the EPA opened a 30-day comment period on a proposed consent decree that would obligate the EPA to propose MACT regulations for mercuryMATS and other hazardous air pollutants by March 16, 2011, andenvironmental regulations. In addition, MP will make a filing with the WVPSC to finalizeprovide them with information regarding the regulations by November 16, 2011. FGCO’sretirement of its plants. Depending on how the MATS are ultimately implemented, FirstEnergy's future cost of compliance with MACT regulationsMATS may be substantial and will depend on the action taken by the EPA and on how any future regulations are ultimately implemented.other changes to FirstEnergy's operations may result.

Pennsylvania has submitted a new mercury rule for EPA approvalOn February 24, 2012, PJM notified FirstEnergy of its preliminary analysis of the reliability impacts that does not provide a cap-and-trade approach asmay result from closure of the older competitive coal-fired generating units. PJM's preliminary analysis indicated that there would be significant reliability concerns that will need to be addressed. FirstEnergy intends to continue to actively engage in discussions with PJM regarding this notification, including the CAMR, but rather follows a command-and-control approach imposing emission limits on individual sources. On December 23, 2009, the Supreme Courtpossible continued operation of Pennsylvania affirmed the Commonwealth Court of Pennsylvania ruling that Pennsylvania’s mercury rule is “unlawful, invalid and unenforceable” and enjoined the Commonwealth from continued implementation or enforcement of that rule.certain plants.

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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 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, in June 2009. Certain states, primarily the northeastern states participating in the RGGI and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.
In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that required FirstEnergy to measure and report GHG emissions commencing in 2010. In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA's finding concludes that concentrations of several key GHGs increase the threat of climate change and may be regulated as “air pollutants” under the CAA. In April 2010, the EPA finalized new 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 would not be triggered for electric generating plants and other stationary sources until January 2, 2011, at the earliest. In May 2010, the EPA finalized new thresholds for GHG emissions that define when permits under the CAA's NSR program would be required. The EPA established an emissions applicability threshold of75,000tons per year of CO2equivalents effective January 2, 2011, for existing facilities under the CAA's PSD program.
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 man-made GHG, including CO2, emitted by developed countries


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by 2012. A December 2009 U.N. Climate Change Conference in Copenhagen did not reach a consensus on a successor treaty to the Kyoto Protocol, but did take note of the Copenhagen Accord, a non-binding political agreement whichthat recognized the scientific view that the increase in global temperature should be belowtwodegrees Celsius, includedCelsius; includes a commitment by developed countries to provide funds, approaching $30$30 billionover the next three years with a goal of increasing to $100$100 billionby 2020,2020; and establishedestablishes the “Copenhagen Green“Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. OnceTo the extent that 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 targets from 2020, while developing countries, including Brazil, China and India, would agree to take mitigation actions, subject to their domestic measurement, reporting and verification. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHGA December 2011 U.N. Climate Change Conference 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 considerDurban, Africa, established a number of measures to regulate GHG emissions. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states, led by California, have coordinated effortsnegotiating process to develop regional strategiesa new post-2020 climate change protocol, called the “Durban Platform for Enhanced Action”. This negotiating process contemplates developed countries, as well as developing countries such as China, India, Brazil, and South Africa, to control emissions ofundertake legally binding commitments post-2020. In addition, certain GHGs.

On April 2, 2007,countries agreed to extend the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. In December 2009, the EPA released its final “Endangerment and Cause or Contribute FindingsKyoto Protocol for Greenhouse Gases under the Clean Air Act.” The EPA’s finding concludes that the atmospheric concentrations of several key GHG 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 GHG and hence to the threat of climate change. Although the EPA’s finding does not establish emission requirements for motor vehicles, such requirements are expected to occur through further rulemakings. Additionally, while the EPA’s endangerment findings do not specifically address stationary sources, including electric generating plants  EPA’s expected establishment of emission requirements for motor vehicles would be expected to support the establishment of future emission requirements by the EPA for stationary sources. In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that will require FirstEnergy to measure GHG emissionssecond commitment period, commencing in 20102013 and submit reports commencingexpiring in 2011. Also in September 2009, EPA proposed new thresholds for GHG emissions that define when CAA permits under the NSR and Title V operating permits programs would be required. EPA is proposing a major source emissions applicability threshold of 25,000 tons per year (tpy) of carbon dioxide equivalents (CO2e) for existing facilities under the Title V operating permits program and the Prevention of Significant Determination (PSD) portion of NSR. EPA is also proposing a significance level between 10,000 and 25,000 tpy CO2e to determine if existing major sources making modifications that result in an increase of emissions above the significance level would be required to obtain a PSD permit.2018 or 2020.

On September 21,In 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. 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. While FirstEnergy is notThe U.S. Supreme Court granted a partywrit of certiorari to either litigation, shouldreview the courtsdecision of appeals decisions be affirmed or not subjectedthe Second Circuit. On June 20, 2011, the U.S. Supreme Court reversed the Second Circuit but failed to further review, FirstEnergy and/or one or moreanswer the question of its subsidiaries could be named inthe extent to which actions making similar allegations.

for damages based on GHG emissions may remain viable. The Court remanded to the Second Circuit the issue of whether the CAA preempted state common law nuisance actions.
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 of its 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 ActCWA and its amendments, apply to FirstEnergy's plants. In addition, Ohio, New Jersey and Pennsylvaniathe states in which FirstEnergy operates have water quality standards applicable to FirstEnergy's operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such authority.

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On September 7,In 2004, the EPA established new performance standards under Section 316(b) of the Clean Water ActCWA for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). On January 26,In 2007, the United States Court of Appeals for the Second Circuit remandedinvalidated portions of the rulemaking dealing with impingement mortalitySection 316(b) performance standards and entrainment back to the EPA for further rulemaking and eliminatedhas taken 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. OnIn 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 ActCWA authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. On March 28, 2011, the EPA is developingreleased a new proposed regulation under Section 316(b) of the Clean Water Act consistent withCWA generally requiring fish impingement to be reduced to a12%annual average and studies to be conducted at the opinionsmajority of our existing generating facilities to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic life. On July 19, 2011, the Supreme Court andEPA extended the Court of Appeals which have created significant uncertainty aboutpublic comment period for the specific nature, scope and timing of thenew proposed Section 316(b) regulation by30days but stated its schedule for issuing a final performance standard.rule remains July 27, 2012. 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. Depending on the results of such studies and the EPA’sEPA'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 April 2011, the U.S. Attorney's Office in Cleveland, Ohio has advised FGCO that it is no longer considering prosecution under the Clean Water ActCWA 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. On August 5, 2011, EPA issued an information request pursuant to Sections 308 and 311 of the CWA for certain information pertaining to the oil spills and spill prevention measures at FirstEnergy facilities. FirstEnergy responded on October 10, 2011. On February 1, 2012, FirstEnergy executed a tolling agreement with the EPA extending the statute of limitations to July 31, 2012. FGCO does not anticipate any losses resulting from this matter to be material.
In May 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club filed a CWA citizen suit alleging violations of arsenic limits in the NPDES water discharge permit for the fly ash impoundments at the Albright Station seeking unspecified civil penalties and injunctive relief. The MP filed an answer on July 11, 2011, and a motion to stay the proceedings on July 13, 2011. On January 3, 2012, the Court denied MP's motion to dismiss or stay the CWA citizen suit but without prejudice to re-filing in the future. MP is unablecurrently seeking relief from the arsenic limits through WVDEP agency review.



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In June 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club served a60-Day Notice of Intent required prior to filing a citizen suit under the CWA for alleged failure to obtain a permit to construct the fly ash impoundments at the Albright Plant.
FirstEnergy intends to vigorously defend against the CWA matters described above but, except as indicated above, cannot predict their outcomes or estimate the possible loss or range of loss.
Monongahela River Water Quality
In late 2008, the PA DEP imposed water quality criteria for certain effluents, including TDS and sulfate concentrations in the Monongahela River, on new and modified sources, including the scrubber project at the coal-fired Hatfield's Ferry Plant. These criteria are reflected in the current PA DEP water discharge permit for that project. AE Supply appealed the PA DEP's permitting decision, which would require it to incur estimated costs in excess of$150 millionin order to install technology to meet TDS and sulfate limits in the permit or negatively affect its ability to operate the scrubbers as designed. The permit has been independently appealed by Environmental Integrity Project and Citizens Coal Council, which seeks to impose more stringent technology-based effluent limitations. Those same parties have intervened in the appeal filed by AE Supply, and both appeals have been consolidated for discovery purposes. An order has been entered that stays the permit limits that AE Supply has challenged while the appeal is pending. A hearing on the parties' appeals was scheduled to begin in September 2011, however the Court stayed all prehearing deadlines on July 15, 2011 to allow the parties additional time to work out a settlement, and has rescheduled a hearing, if necessary, for July 2012. If these settlement discussions are successful, AE Supply anticipates that its obligations will not be material. AE Supply intends to vigorously pursue these issues, but cannot predict the outcome of these appeals or estimate the possible loss or range of loss.
In a parallel rulemaking, the PA DEP recommended, and in August 2010, the Pennsylvania Environmental Quality Board issued, a final rule imposing end-of-pipe TDS effluent limitations. FirstEnergy could incur significant costs for additional control equipment to meet the requirements of this matter.rule, although its provisions do not apply to electric generating units until the end of 2018, and then only if the EPA has not promulgated TDS effluent limitation guidelines applicable to such units.
In December 2010, PA DEP submitted its CWA 303(d) list to the EPA with a recommended sulfate impairment designation for an approximately68mile stretch of the Monongahela River north of the West Virginia border. In May 2011, the EPA agreed with PA DEP's recommended sulfate impairment designation. PA DEP's goal is to submit a final water quality standards regulation, incorporating the sulfate impairment designation for EPA approval by May, 2013. PA DEP will then need to develop a TMDL limit for the river, a process that will take approximatelyfiveyears. Based on the stringency of the TMDL, FirstEnergy may incur significant costs to reduce sulfate discharges into the Monongahela River from the coal-fired Hatfield's Ferry and Mitchell Plants in Pennsylvania and the coal-fired Fort Martin Plant in West Virginia.
In October 2009, the WVDEP issued the water discharge permit for the Fort Martin Plant. Similar to the Hatfield's Ferry water discharge permit, the Fort Martin permit imposes effluent limitations for TDS and sulfate concentrations. The permit also imposes temperature limitations and other effluent limits for heavy metals that are not contained in the Hatfield's Ferry water discharge permit. Concurrent with the issuance of the Fort Martin permit, WVDEP also issued an administrative order that sets deadlines for MP to meet certain of the effluent limits that are effective immediately under the terms of the permit. MP appealed the Fort Martin permit and the administrative order. The appeal included a request to stay certain of the conditions of the permit and order while the appeal is pending, which was granted pending a final decision on appeal and subject to WVDEP moving to dissolve the stay. The appeals have been consolidated. MP moved to dismiss certain of the permit conditions for the failure of the WVDEP to submit those conditions for public review and comment during the permitting process. An agreed-upon order that suspends further action on this appeal, pending WVDEP's release for public review and comment on those conditions, was entered on August 11, 2010. The stay remains in effect during that process. The current terms of the Fort Martin permit would require MP to incur significant costs or negatively affect operations at Fort Martin. Preliminary information indicates an initial capital investment in excess of the capital investment that may be needed at Hatfield's Ferry in order to install technology to meet the TDS and sulfate limits in the Fort Martin permit, which technology may also meet certain of the other effluent limits in the permit. Additional technology may be needed to meet certain other limits in the permit. MP intends to vigorously pursue these issues but cannot predict the outcome of these appeals or estimate the possible loss or range of loss.
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's evaluation of the need for future regulation. In February 2009, the EPA requested comments from the states on options for regulating coal combustion wastes,residuals, including regulationwhether they should be regulated as hazardous or non-hazardous waste or regulation as a hazardous waste. In March and June 2009, the EPA requested information from FGCO’s Bruce Mansfield Plant regarding the management of coal combustion wastes.
In December 2009, EPA provided to FGCO the findings of its review of the Bruce Mansfield Plant’s coal combustion waste management practices.  EPA observed that the waste management structures and the Plant “appeared to be well maintained and in good working order” and recommended only that FGCO “seal and maintain all asphalt surfaces.” On December 30, 2009, in an advancedadvance notice of public rulemaking, the EPA saidasserted that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. Additional regulationsIn May 2010, the EPA proposedtwooptions for additional regulation of fossil-fuelcoal combustion residuals, including the option of regulation as a special waste productsunder the EPA's hazardous waste management program which could have a significant impact on ourthe management, beneficial use and disposal of coal ash. FGCO'scombustion residuals. FirstEnergy's future cost of compliance with any coal combustion wasteresiduals regulations whichthat may be promulgated could


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be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the EPA or the states. Compliance with those regulations could have an adverse impact on FirstEnergy's results of operations and financial condition.
LBR CCB impoundment is expected to run out of disposal capacity for disposal of CCBs from the BMP between 2016 and 2018. BMP is pursuing several CCB disposal options.
The UtilitiesCertain of our 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 ofDecember 31, 2009,2011, based on estimates of the total costs of cleanup, the Utilities'Utility Registrants' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay.Total liabilities of approximately $101$106 million (JCP(JCP&L - - $74$70 million, TE - $1$1 million, CEI - $1$1 million, FGCO - $1$1 millionand FirstEnergyFE - $24$33 million) have been accrued throughDecember 31, 2009.2011. Included in the total are accrued liabilities of approximately $67$63 millionfor 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. On July 11, 2011, FirstEnergy was found to be a potentially responsible party under CERCLA, indirectly liable for a portion of past and future clean-up costs at certain legacy MGP sites, estimated to total approximately$59 million. FirstEnergy recognized an additional expense of$29 millionduring the second quarter of 2011;$30 millionhad previously been reserved prior to 2011.FirstEnergy determined that it is reasonably possible that it or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the possible losses or range of losses cannot be determined or reasonably estimated at this time.
Fuel Supply
FirstEnergy currently has long-term coal contracts with various terms to acquire approximately 34.5 million tons of coal for the year 2012 which is approximately 90% of its 2012 coal requirements of 38.5 million tons. This coal requirement excludes the impact of our recently announced decision to close nine older coal-fired plants by September 1, 2012, subject to review for reliability impacts by PJM. This contract coal is produced primarily from mines located in Ohio, Pennsylvania, West Virginia, Montana and Wyoming. The contracts expire at various times through December 31, 2030. See “Environmental Matters” for factors pertaining to meeting environmental regulations affecting coal-fired generating units.
FirstEnergy has contracts for all uranium requirements through 2012 and a portion of uranium material requirements through 2024. Conversion services contracts fully cover requirements through 2012 and partially fill requirements through 2024. Enrichment services are contracted for essentially all of the enrichment requirements for nuclear fuel through 2020. A portion of enrichment requirements is also contracted for through 2024. Fabrication services for fuel assemblies are contracted for both Beaver Valley units through 2013 and Davis-Besse through 2025 and through the current operating license period for Perry. In addition to the existing commitments, FirstEnergy intends to make additional arrangements for the supply of uranium and for the subsequent conversion, enrichment, fabrication, and waste disposal services.

On-site spent fuel storage facilities are expected to be adequate for Beaver Valley Unit 1 through 2014. Davis-Besse has adequate storage through 2017. FENOC is taking actions to extend the spent fuel storage capacity for Beaver Valley Units 1 and 2 and Perry. Plant modifications to increase the storage capacity of the existing spent fuel storage pool at Beaver Valley Unit 2 were approved by the NRC on April 29, 2011 and the plant modifications are expected to be complete in 2012. Once this expansion is complete, Beaver Valley Unit 2 will have spent fuel pool storage capacity through 2022. Dry fuel storage is also being pursued at Beaver Valley with completion projected by the end of 2014. Perry dry fuel storage facilities have been completed with the initial dry fuel storage loading campaign targeted for 2012. Both Beaver Valley Unit 2 and Perry maintain sufficient fuel storage capability to continue operations through the targeted completion dates of their respective storage expansion projects. After current on-site storage capacity at the plants is exhausted, additional storage capacity will have to be obtained either through plant modifications, interim off-site disposal, or permanent waste disposal facilities.

The Federal Nuclear Waste Policy Act of 1982 provided for the construction of facilities for the permanent disposal of high-level nuclear wastes, including spent fuel from nuclear power plants operated by electric utilities. NGC has contracts with the DOE for the disposal of spent fuel for Beaver Valley, Davis-Besse and Perry. Yucca Mountain was approved in 2002 as a repository for underground disposal of spent nuclear fuel from nuclear power plants and high level waste from U.S. defense programs. The DOE submitted the license application for Yucca Mountain to the NRC on June 3, 2008. On March 3, 2010, the DOE filed a motion to withdraw its Yucca Mountain license application with prejudice. The ASLB denied the DOE's withdrawal motion on June 29, 2010. On September 9, 2011, the NRC issued an Order (CLI-11-07) stating that it was evenly divided on whether to overturn or uphold the ASLB's decision, and directing the ASLB to complete all necessary and appropriate case management activities by the close of the fiscal year. The current Administration has stated the Yucca Mountain repository will not be completed and a Federal review of potential alternative strategies is being performed. The President's 2011 budget proposal eliminated funding for Yucca Mountain, and the 2011 DOE appropriation did not include any funds for Yucca Mountain. Likewise, the President's 2012 budget proposal does not provide for funding of Yucca Mountain.

In parallel, several parties filed actions in the U.S. Circuit Court of Appeals for the D.C. Circuit challenging the Department's authority to withdraw the license application in light of its obligations under the Nuclear Waste Policy Act. The first case filed was In re: Aiken County, filed on February 19, 2010. Robert L. Ferguson, et al. filed a petition on February 25, 2010; State of South Carolina filed


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on March 26, 2010; and State of Washington filed on April 13, 2010. These cases have since been consolidated. On May 3, 2010, the D.C. Circuit granted a motion by the National Association of Regulatory Utility Commissioners to intervene. Oral arguments were heard by the D.C. Circuit on March 22, 2011. The D.C. Circuit dismissed the petitions for lack of jurisdiction on July 1, 2011, finding a lack of finality and ripeness until the Commission acts on DOE's motion to withdraw or rules on the license application. In response to the NRC's order from September 2011, the states and other interested parties re-commenced their challenge at the D. C. Circuit, in Aiken County et al., No. 11-1271. Briefing in that appeal was recently completed, and oral argument has been set for May 2, 2012. In light of this uncertainty, FirstEnergy intends to make additional arrangements for storage capacity as a contingency for the continuing delays of the DOE acceptance of spent fuel for disposal.

Fuel oil and natural gas are used primarily to fuel peaking units and/or to ignite the burners prior to burning coal when a coal-fired plant is restarted. Fuel oil requirements have historically been low and are forecasted to remain so. Requirements are expected to average approximately 4 million gallons per year over the next five years. Natural gas is currently consumed primarily by peaking units and demand is forecasted at less than 7 million mcf in 2012.
System Demand
The 2011 maximum hourly demand for each of the Utilities was:
OE—6,070 MW on July 21, 2011;
Penn—1,048 MW on July 21, 2011;
CEI—4,648 MW on July 21, 2011;
TE—2,286 MW on July 21, 2011;
JCP&L—6,588 MW on July 22, 2011;
Met-Ed—3,094 MW on July 22, 2011;
Penelec—3,128 MW on July 22, 2011;
MP—1,989 MW on July 21, 2011;
PE—2,969 MW on July 21, 2011; and
WP—4,017 MW on July 21, 2011
Supply Plan
Regulated Commodity Sourcing
Certain of the Utilities have default service obligations to provide power to non-shopping customers who have elected to continue to receive service under regulated retail tariffs. The volume of these sales can vary depending on the level of shopping that occurs. Supply plans vary by state and by service territory. JCP&L’s default service or BGS supply is secured through a statewide competitive procurement process approved by the NJBPU. The Ohio Companies', Pennsylvania Companies' and PE's Maryland default service supplies are provided through a competitive procurement process approved by the PUCO (under the ESP), PPUC (under the DSP) and MDPSC (under the SOS), respectively. If any supplier fails to deliver power to any one of those Utilities’ service areas, the Utility serving that area may need to procure the required power in the market in their role as a POLR. West Virginia electric generation continues to be regulated by the WVPSC.
Unregulated Commodity Sourcing
The Competitive Energy Services segment, through FES and AE Supply, provides energy and energy related services, including the generation and sale of electricity and energy planning and procurement through retail and wholesale competitive supply arrangements. FES supplies the power requirements of its competitive load-serving obligations through a combination of subsidiary-owned generation, non-affiliated contracts and spot market transactions.
FES and AE Supply have retail and wholesale competitive load-serving obligations in Ohio, Pennsylvania, Illinois, Maryland, Michigan and New Jersey, serving both affiliated and non-affiliated companies. FES and AE Supply provide energy products and services to customers under various POLR, shopping, competitive-bid and non-affiliated contractual obligations. Geographically, most of FES’ and AE Supply's obligations are in the PJM market area where all of its respective generation facilities are located.
Regional Reliability
All of FirstEnergy's facilities are located within PJM and operate under the reliability oversight of a regional entity known as RFC. This regional entity operates under the oversight of the NERC in accordance with a Delegation Agreement approved by the FERC. RFC began operations under the NERC on January 1, 2006. On July 20, 2006, the NERC was certified by the FERC as the ERO


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in the United States pursuant to Section 215 of the FPA and RFC was certified as a regional entity.
Competition
As a result of actions taken by state legislative bodies, major changes in the electric utility business have occurred in portions of the United States, including Ohio, New Jersey, Pennsylvania and Maryland, where most of FirstEnergy utility subsidiaries operate. These changes have altered the way traditional integrated utilities conduct their business. FirstEnergy has aligned its business units to participate in the competitive electricity marketplace (see Management's Discussion and Analysis for more information regarding FirstEnergy's Competitive Energy Services segment).
FirstEnergy's Competitive Energy Services segment participates in deregulated energy markets in Ohio, Pennsylvania, Maryland, Michigan, New Jersey and Illinois, through FES and AE Supply. In these markets, the Competitive Energy Services segment competes: (1) to provide retail generation service directly to end users; (2) to provide wholesale generation service to utilities, municipalities and co-operatives, which, in turn, resell to their end users, and (3) in the wholesale market. The success of the Competitive Energy Services segment is driven by its ability to successfully compete against other retail markets and/or generators and to produce revenues that exceed costs.
Seasonality
The sale of electric power is generally a seasonal business and weather patterns can have a material impact on FirstEnergy’s operating results. Demand for electricity in our service territories historically peaks during the summer and winter months, with market prices also generally peaking at that time. Accordingly, FirstEnergy’s annual results of operations and liquidity position may depend disproportionately on its operating performance during the summer and winter. Mild weather conditions may result in lower power sales and consequently lower earnings.
Research and Development
The Utilities, FES, FGCO and FENOC participate in the funding of EPRI, which was formed for the purpose of expanding electric R&D under the voluntary sponsorship of the nation’s electric utility industry — public, private and cooperative. Its goal is to mutually benefit utilities and their customers by promoting the development of new and improved technologies to help the utility industry meet present and future electric energy needs in environmentally and economically acceptable ways. EPRI conducts research on all aspects of electric power production and use, including fuels, generation, delivery, energy management and conservation, environmental effects and energy analysis. The majority of EPRI’s research and development projects are directed toward practical solutions and their applications to problems currently facing the electric utility industry.
FirstEnergy participates in other initiatives with industry R&D consortiums and universities to address technology needs for its various business units. Participation in these consortiums helps the company address research needs in areas such as plant operations and maintenance, major component reliability, environmental controls, advanced energy technologies, and transmission and distribution system infrastructure to improve performance, and develop new technologies for advanced energy and grid applications.


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Executive Officers
Name Age Positions Held During Past Five Years Dates
A. J. Alexander 60  President and Chief Executive Officer (A)(B) *-present
    Chief Executive Officer (F) *-present
    President and Chief Executive Officer (H) 2011-present
    President (C)(D) *-2008
       
L. M. Cavalier 60  Senior Vice President, Human Resources (B) *-present
    Senior Vice President, Human Resources (H) 2011-present
       
M. T. Clark 61  President and Chief Financial Officer (G)(L) 2012-present
    Executive Vice President and Chief Financial Officer (A)(B)(C)(D)(E)(F) 2009-present
    Executive Vice President and Chief Financial Officer (H)(I)(J)(K) 2011-present
    Executive Vice President and Chief Financial Officer (G) 2011
    Executive Vice President, Strategic Planning & Operations (A)(B) 2008-2009
    Senior Vice President, Strategic Planning & Operations (B) *-2008
       
M. J. Dowling 47 Senior Vice President, External Affairs (B)(H) 2011-present
    Vice President, External Affairs (B) 2010-2011
    Vice President, Communications (B) 2008-2010
    Vice President, Governmental Affairs (B) 2007-2008
    Vice President (B) *-2007
       
C. E. Jones 56  Senior Vice President & President, FirstEnergy Utilities (B) 2010-present
    Senior Vice President & President, FirstEnergy Utilities (H) 2011-present
    President (J)(K) 2011-present
    President (C)(D) 2010-present
    Senior Vice President & President, FirstEnergy Utilities (A) 2010-2011
    Senior Vice President, Energy Delivery & Customer Service (B) 2009-2010
    President (E) 2007-2009
    Senior Vice President (B)(C)(D) *-2007
       
J. H. Lash 61  President FE, Generation (B)(H) 2011-present
    Chief Nuclear Officer (F) 2011-present
    President (I) 2011-present
    President and Chief Nuclear Officer (F) 2010-2011
    Senior Vice President and Chief Operating Officer (F) 2007-2010
    Vice President, Beaver Valley (F) *-2007
       
G. R. Leidich 61  Executive Vice President, Integration (A)(B)(H)(M) 2011
    President (G)(M) 2011
    Executive Vice President & President, FirstEnergy Generation (A)(B)(M) 2008-2011
    Senior Vice President, Operations (B) 2007-2008
    President and Chief Nuclear Officer (F) *-2007
       
J. F. Pearson 57  Vice President and Treasurer (A)(B)(C)(D)(E)(F) *-present
    Vice President and Treasurer (G)(H)(I)(J)(K) 2011-present
       
D. R. Schneider 50  President (E) 2009-present
    Senior Vice President, Energy Delivery & Customer Service (B) 2007-2009
    Senior Vice President (C)(D) 2007-2009
    Vice President (B) *-2007
       
L. L. Vespoli 52  Executive Vice President and General Counsel (A)(B)(C)(D)(E)(F) 2008-present
    Executive Vice President and General Counsel (G)(H)(I)(J)(K) 2011-present
    Senior Vice President and General Counsel (A)(B)(C)(D)(E)(F) *-2008
       
H. L. Wagner 59  Vice President, Controller and Chief Accounting Officer (A) *-present
    Vice President and Controller (C)(D)(E)(F) *-present
    Vice President and Controller (G)(I)(J)(K) 2011-present
    Vice President, Controller and Chief Accounting Officer (H) 2011-present
    Vice President, Controller and Chief Accounting Officer (B) 2010-present
    Vice President and Controller (B) *-2010
* Indicates position held at least since January 1, 2007(E) Denotes executive officer of FES(J) Denotes executive officer of MP, PE and WP
(A) Denotes executive officer of FE(F) Denotes executive officer of FENOC(K) Denotes executive officer of TrAIL
(B) Denotes executive officer of FESC(G) Denotes executive officer of AE(L) Position effective January 1, 2012
(C) Denotes executive officer of OE, CEI and TE(H) Denotes executive officer of AESC(M) Retired on December 31, 2011
(D) Denotes executive officer of Met-Ed, Penelec and Penn(I) Denotes executive officer of AGC


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Employees
As of December 31, 2011, FirstEnergy’s subsidiaries had 17,257 employees located in the United States as follows:
 
Total
Employees
 
Bargaining
Unit
Employees
FESC2,975
 293
AESC(1)
3,971
 1,177
OE1,222
 714
CEI897
 608
TE390
 290
Penn204
 153
JCP&L1,413
 1,090
Met-Ed678
 488
Penelec896
 638
ATSI38
 —
FES273
 —
FGCO1,652
 1,061
FENOC2,648
 957
Total17,257
 7,469
(1)
AESC employs substantially all of the former Allegheny personnel who provide services to AE and its subsidiaries, including AE Supply, AGC, MP, PE, WP and TrAIL.
FirstEnergy Web Site
Each of the registrant’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are also made available free of charge on or through FirstEnergy’s internet Web site at www.firstenergycorp.com. These reports are posted on the Web site as soon as reasonably practicable after they are electronically filed with the SEC. Additionally, we routinely post important information on our Web site and recognize our Web site as a channel of distribution to reach public investors and as a means of disclosing material non-public information for complying with disclosure obligations under the SEC's Regulation FD. Information contained on FirstEnergy’s Web site shall not be deemed incorporated into, or to be part of, this report.
In accordance with SEC rules, FirstEnergy will include disclosure of any amendment or waiver to its Code of Ethics or a provision of that Code on its Internet Web site within four business days following the date of any such amendment or waiver.
ITEM 1A.RISK FACTORS
We operate in a business environment that involves significant risks, many of which are beyond our control. Management of each Registrant regularly evaluates the most significant risks of the Registrant’s businesses and reviews those risks with the FirstEnergy Board of Directors or appropriate Committees of the Board. The following risk factors and all other information contained in this report should be considered carefully when evaluating FirstEnergy and our subsidiaries. These risk factors could affect our financial results and cause such results to differ materially from those expressed in any forward-looking statements made by or on behalf of us. Below, we have identified risks we currently consider material. Additional information on risk factors is included in “Item 1. Business” and “Item 7. Management’s Discussion and Analysis of Registrant and Subsidiaries” and in other sections of this Form 10-K that include forward-looking and other statements involving risks and uncertainties that could impact our business and financial results.
Risks Related to Business Operations
Risks Arising from the Reliability of Our Power Plants and Transmission and Distribution Equipment
Operation of generation, transmission and distribution facilities involves risk, including the risk of potential breakdown or failure of equipment or processes due to aging infrastructure, fuel supply or transportation disruptions, accidents, labor disputes or work stoppages by employees, acts of terrorism or sabotage, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions resulting from environmental limitations and governmental interventions, and performance below expected levels. In addition, weather-related incidents and other natural disasters can disrupt generation, transmission and distribution delivery systems. Because our transmission facilities are interconnected with those of third parties, the operation of our facilities could be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties.


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Operation of our power plants below expected capacity could result in lost revenues and increased expenses, including higher operating and maintenance costs, purchased power costs and capital requirements. Unplanned outages of generating units and extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of our business. Unplanned outages typically increase our operation and maintenance expenses and may reduce our revenues as a result of selling fewer MWH or may require us to incur significant costs as a result of operating our higher cost units or obtaining replacement power from third parties in the open market to satisfy our forward power sales obligations. Moreover, if we were unable to perform under contractual obligations, penalties or liability for damages could result.
FES, FGCO and the Ohio Companies are exposed to losses under their applicable sale-leaseback arrangements for generating facilities upon the occurrence of certain contingent events that could render those facilities worthless. Although we believe these types of events are unlikely to occur, FES, FGCO and the Ohio Companies have a maximum exposure to loss under those provisions of approximately $1.4 billion for FES, $606 million for OE and an aggregate of $587 million for TE and CEI as co-lessees.
We remain obligated to provide safe and reliable service to customers within our franchised service territories. Meeting this commitment requires the expenditure of significant capital resources. Failure to provide safe and reliable service and failure to meet regulatory reliability standards due to a number of factors, including, but not limited to, equipment failure and weather, could adversely affect our operating results through reduced revenues and increased capital and operating costs and the imposition of penalties/fines or other adverse regulatory outcomes.
Changes in Commodity Prices Could Adversely Affect Our Profit Margins
We purchase and sell electricity in the competitive wholesale and retail markets. Increases in the costs of fuel for our generation facilities (particularly coal, uranium and natural gas) can affect our profit margins. Changes in the market price of electricity, which are affected by changes in other commodity costs and other factors, may impact our results of operations and financial position by increasing the amount we pay to purchase power to supply POLR and default service obligations in the states we do business. In addition, the global economy could lead to lower international demand for coal, oil and natural gas, which may lower fossil fuel prices and put downward pressure on electricity prices.
Electricity and fuel prices may fluctuate substantially over relatively short periods of time for a variety of reasons, including:
changing weather conditions or seasonality;
changes in electricity usage by our customers;
illiquidity and credit worthiness of participants in wholesale power and other markets;
transmission congestion or transportation constraints, inoperability or inefficiencies;
availability of competitively priced alternative energy sources;
changes in supply and demand for energy commodities;
changes in power production capacity;
outages at our power production facilities or those of our competitors;
changes in production and storage levels of natural gas, lignite, coal, crude oil and refined products;
changes in legislation and regulation; and
natural disasters, wars, acts of sabotage, terrorist acts, embargoes and other catastrophic events.
We Are Exposed to Operational, Price and Credit Risks Associated With Selling and Marketing Products in the Power Markets That We Do Not Always Completely Hedge Against
We purchase and sell power at the wholesale level under market-based tariffs authorized by the FERC, and also enter into agreements to sell available energy and capacity from our generation assets. If we are unable to deliver firm capacity and energy under these agreements, we may be required to pay damages. These damages would generally be based on the difference between the market price to acquire replacement capacity or energy and the contract price of the undelivered capacity or energy. Depending on price volatility in the wholesale energy markets, such damages could be significant. Extreme weather conditions, unplanned power plant outages, transmission disruptions, and other factors could affect our ability to meet our obligations, or cause increases in the market price of replacement capacity and energy.
We attempt to mitigate risks associated with satisfying our contractual power sales arrangements by reserving generation capacity to deliver electricity to satisfy our net firm sales contracts and, when necessary, by purchasing firm transmission service. We also routinely enter into contracts, such as fuel and power purchase and sale commitments, to hedge our exposure to fuel requirements and other energy-related commodities. We may not, however, hedge the entire exposure of our operations from commodity price


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volatility. To the extent we do not hedge against commodity price volatility, our results of operations and financial position could be negatively affected.
The Use of Derivative Contracts by Us to Mitigate Risks Could Result in Financial Losses That May Negatively Impact Our Financial Results
We use a variety of non-derivative and derivative instruments, such as swaps, options, futures and forwards, to manage our commodity and financial market risks. In the absence of actively quoted market prices and pricing information from external sources, the valuation of some of these derivative instruments involves management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of some of these contracts. Also, we could recognize financial losses as a result of volatility in the market values of these contracts or if a counterparty fails to perform.
Financial Derivatives Reforms Could Increase Our Liquidity Needs and Collateral Costs and Impose Additional Regulatory Burdens
In July 2010, federal legislation was enacted to reform financial markets that significantly alter how OTC derivatives are regulated. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank) increased regulatory oversight of OTC derivatives, including (1) requiring standardized OTC derivatives to be traded on registered exchanges regulated by the CFTC, (2) imposing new and potentially higher capital and margin requirements and (3) authorizing the establishment of overall volume and position limits. The law gives the CFTC authority to exempt companies that participate in the swap market as “end users” for hedging purposes which could reduce, but not eliminate, the applicability of these measures to us. These requirements could cause our OTC transactions to be more costly and have an adverse effect on our liquidity due to additional capital requirements. In addition, as these reforms aim to standardize OTC products it could limit the effectiveness of our hedging programs because we would have less ability to tailor OTC derivatives to match the precise risk we are seeking to protect.
We rely on the OTC derivative markets as part of our program to hedge the price risk associated with our power portfolio. The effect on our operations of this legislation will depend in part on whether we are determined to be a swap dealer, a major swap participant or a qualifying end-user through a self-identification process, based on the meaning of those terms to be established in the final rules. If we are determined to be a swap dealer or a major swap participant, we will be required to register with the CFTC and execute most bilateral OTC derivative transactions through an exchange or central clearinghouse. This requirement could require us to commit substantial additional capital to cover increases in collateral costs associated with margin requirements of the major exchanges. We would also be required to comply with increased reporting and record-keeping requirements and follow CFTC-specified business conduct standards, and adhere to position limits in a potentially broad range of energy commodities.
Even if we are not determined to be a swap dealer or a major swap participant, we will be required to comply with additional regulatory obligations under Dodd-Frank, which includes some reporting requirements, clearing some additional transactions that we would otherwise enter into over-the-counter, and having to adhere to position limits. Also, the total burden that the rules could impose on all market participants could cause liquidity in the bilateral OTC swap market to decrease substantially. The new rules could impede our ability to meet our hedge targets in a cost-effective manner. FirstEnergy cannot predict the ultimate outcome that Dodd-Frank will have on its results of operations, cash flows or financial position.
Our Risk Management Policies Relating to Energy and Fuel Prices, and Counterparty Credit, Are by Their Very Nature Risk Related, and We Could Suffer Economic Losses Despite Such Policies
We attempt to mitigate the market risk inherent in our energy, fuel and debt positions. Procedures have been implemented to enhance and monitor compliance with our risk management policies, including validation of transaction and market prices, verification of risk and transaction limits, sensitivity analysis and daily portfolio reporting of various risk measurement metrics. Nonetheless, we cannot economically hedge all of our exposures in these areas and our risk management program may not operate as planned. For example, actual electricity and fuel prices may be significantly different or more volatile than the historical trends and assumptions reflected in our analyses. Also, our power plants might not produce the expected amount of power during a given day or time period due to weather conditions, technical problems or other unanticipated events, which could require us to make energy purchases at higher prices than the prices under our energy supply contracts. In addition, the amount of fuel required for our power plants during a given day or time period could be more than expected, which could require us to buy additional fuel at prices less favorable than the prices under our fuel contracts. As a result, we cannot always predict the impact that our risk management decisions may have on us if actual events lead to greater losses or costs than our risk management positions were intended to hedge.
Our risk management activities, including our power sales agreements with counterparties, rely on projections that depend heavily on judgments and assumptions by management of factors such as future market prices and demand for power and other energy-related commodities. These factors become more difficult to predict and the calculations become less reliable the further into the future these estimates are made. Even when our policies and procedures are followed and decisions are made based on these estimates, results of operations may be diminished if the judgments and assumptions underlying those calculations prove to be inaccurate.
We also face credit risks from parties with whom we contract who could default in their performance, in which cases we could be forced to sell our power into a lower-priced market or make purchases in a higher-priced market than existed at the time of executing


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the contract. Although we have established risk management policies and programs, including credit policies to evaluate counterparty credit risk, there can be no assurance that we will be able to fully meet our obligations, that we will not be required to pay damages for failure to perform or that we will not experience counterparty non-performance or that we will collect for voided contracts. If counterparties to these arrangements fail to perform, we may be forced to enter into alternative hedging arrangements or honor underlying commitments at then-current market prices. In that event, our financial results could be adversely affected.
Nuclear Generation Involves Risks that Include Uncertainties Relating to Health and Safety, Additional Capital Costs, the Adequacy of Insurance Coverage and Nuclear Plant Decommissioning
We are subject to the risks of nuclear generation, including but not limited to the following:
the potential harmful effects on the environment and human health resulting from unplanned radiological releases associated with the operation of our nuclear facilities and the storage, handling and disposal of radioactive materials;
limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with our nuclear operations or those of others in the United States;
uncertainties with respect to contingencies and assessments if insurance coverage is inadequate; and
uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed operation including increases in minimum funding requirements or costs of completion.
The NRC has broad authority under federal law to impose licensing security and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines and/or shut down a unit, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants, including ours. Also, a serious nuclear incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or relicensing of any domestic nuclear unit. See "Potential NRC Regulation in Response to the Incident at Japan's Fukushima Daiichi Nuclear Plant Could Adversely Effect Our Business and Financial Condition" below and Note 16, Commitments, Guarantees and Contingencies - Environmental Matters of the Combined Notes to the Consolidated Financial Statements.
We Have a Significant Percentage of Coal-Fired Generation Capacity Which Exposes us to Risk from Regulations Relating to Coal and Coal Combustion Residuals
Approximately 65% of FirstEnergy's generation fleet capacity is coal-fired. Historically, coal-fired generating plants face greater exposure to the costs of complying with federal, state and local environmental statutes, rules and regulations relating to emissions of SO2 and NOx. In addition, the MATS established coal-fired emission standards for mercury, hydrochloric acid and various metals effective in April 2015, proposed coal combustion residual regulations include an option to reclassify coal ash as a hazardous waste, and there are currently a number of federal, state and international initiatives under consideration to, among other things, require reductions in GHG emissions. These legal requirements and initiatives could require substantial additional costs, extensive mitigation efforts and, in the case of GHG requirements, could raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities. Failure to comply with any such existing or future legal requirements may also result in the assessment of fines and penalties. Significant resources also may be expended to defend against allegations of violations of any such requirements.
Capital Market Performance and Other Changes May Decrease the Value of Pension Fund Assets, Decommissioning and Other Trust Funds Which Then Could Require Significant Additional Funding
Our financial statements reflect the values of the assets held in trust to satisfy our obligations to decommission our nuclear generation facilities and under pension and other postemployment benefit plans. The value of certain of the assets held in these trusts do not have readily determinable market values. Changes in the estimates and assumptions inherent in the value of these assets could affect the value of the trusts. If the value of the assets held by the trusts declines by a material amount, our funding obligation to the trusts could materially increase. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. Forecasting investment earnings and costs to decommission nuclear generating stations, to pay future pensions and other obligations requires significant judgment, and actual results may differ significantly from current estimates. Capital market conditions that generate investment losses or increase the present value of liabilities can negatively impact our results of operations and financial position.
We Could be Subject to Higher Costs and/or Penalties Related to Mandatory Reliability Standards Set by NERC/FERC or Changes in the Rules of Organized Markets and the States in Which We Do Business
As a result of the EPACT, owners, operators, and users of the bulk electric system are subject to mandatory reliability standards promulgated by the NERC and approved by FERC as well as mandatory reliability standards and energy efficiency requirements imposed by each of the states in which we operate. The standards are based on the functions that need to be performed to ensure that the bulk electric system operates reliably. Compliance with modified or new reliability standards may subject us to higher operating costs and/or increased capital expenditures. If we were found not to be in compliance with the mandatory reliability


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standards, we could be subject to sanctions, including substantial monetary penalties.
Reliability standards that were historically subject to voluntary compliance are now mandatory and could subject us to potential civil penalties for violations which could negatively impact our business. The FERC can now impose penalties of $1.0 million per day for failure to comply with these mandatory electric reliability standards.
In addition to direct regulation by the FERC and the states, we are also subject to rules and terms of participation imposed and administered by various RTOs and ISOs. Although these entities are themselves ultimately regulated by the FERC, they can impose rules, restrictions and terms of service that are quasi-regulatory in nature and can have a material adverse impact on our business. For example, the independent market monitors of ISOs and RTOs may impose bidding and scheduling rules to curb the potential exercise of market power and to ensure the market functions. Such actions may materially affect our ability to sell, and the price we receive for, our energy and capacity. In addition, the RTOs may direct our transmission owning affiliates to build new transmission facilities to meet the reliability requirements of the RTO or to provide new or expanded transmission service under the RTO tariffs.
We Rely on Transmission and Distribution Assets That We Do Not Own or Control to Deliver Our Wholesale Electricity. If Transmission is Disrupted, Including Our Own Transmission, or Not Operated Efficiently, or if Capacity is Inadequate, Our Ability to Sell and Deliver Power May Be Hindered
We depend on transmission and distribution facilities owned and operated by utilities and other energy companies to deliver the electricity we sell. If transmission is disrupted (as a result of weather, natural disasters or other reasons) or not operated efficiently by ISOs, in applicable markets, or if capacity is inadequate, our ability to sell and deliver products and satisfy our contractual obligations may be hindered, or we may be unable to sell products on the most favorable terms. In addition, in certain of the markets in which we operate, we may be required to pay for congestion costs if we schedule delivery of power between congestion zones during periods of high demand. If we are unable to hedge or recover for such congestion costs in retail rates, our financial results could be adversely affected.
Demand for electricity within our Utilities’ service areas could stress available transmission capacity requiring alternative routing or curtailing electricity usage that may increase operating costs or reduce revenues with adverse impacts to our results of operations. In addition, as with all utilities, potential concerns over transmission capacity could result in MISO, PJM or the FERC requiring us to upgrade or expand our transmission system, requiring additional capital expenditures.
The FERC requires wholesale electric transmission services to be offered on an open-access, non-discriminatory basis. Although these regulations are designed to encourage competition in wholesale market transactions for electricity, it is possible that fair and equal access to transmission systems will not be available or that sufficient transmission capacity will not be available to transmit electricity as we desire. We cannot predict the timing of industry changes as a result of these initiatives or the adequacy of transmission facilities in specific markets or whether independent system operators in applicable markets will operate the transmission networks, and provide related services, efficiently.
Disruptions in Our Fuel Supplies or Changes in Our Fuel Needs Could Occur, Which Could Adversely Affect Our Ability to Operate Our Generation Facilities or Impact Financial Results

We purchase fuel from a number of suppliers. The lack of availability of fuel at expected prices, or a disruption in the delivery of fuel which exceeds the duration of our on-site fuel inventories, including disruptions as a result of weather, increased transportation costs or other difficulties, labor relations or environmental or other regulations affecting our fuel suppliers, could cause an adverse impact on our ability to operate our facilities, possibly resulting in lower sales and/or higher costs and thereby adversely affect our results of operations. Operation of our coal-fired generation facilities is highly dependent on our ability to procure coal. We have long-term contracts in place for a majority of our coal and coal transportation needs. We may from time to time enter into new, or renegotiate certain of these contracts, but can provide no assurance that such contracts will be negotiated or renegotiated, as the case may be, on satisfactory terms, or at all. In addition, if prices for physical delivery are unfavorable, our financial condition, results of operations and cash flows could be materially adversely affected.

Temperature Variations as well as Weather Conditions or other Natural Disasters Could Have a Negative Impact on Our Results of Operations and Demand Significantly Below or Above Our Forecasts Could Adversely Affect Our Energy Margins
Weather conditions directly influence the demand for electric power. Demand for power generally peaks during the summer and winter months, with market prices also typically peaking at that time. Overall operating results may fluctuate based on weather conditions. In addition, we have historically sold less power, and consequently received less revenue, when weather conditions are milder. Severe weather, such as tornadoes, hurricanes, ice or snowstorms, or droughts or other natural disasters, may cause outages and property damage that may require us to incur additional costs that are generally not insured and that may not be recoverable from customers. The effect of the failure of our facilities to operate as planned under these conditions would be particularly burdensome during a peak demand period.
Customer demand could change as a result of severe weather conditions or other circumstances over which we have no control. We satisfy our electricity supply obligations through a portfolio approach of providing electricity from our generation assets, contractual relationships and market purchases. A significant increase in demand could adversely affect our energy margins if we are required to provide the energy supply to fulfill this increased demand at fixed rates, which we expect would remain below the


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wholesale prices at which we would have to purchase the additional supply if needed or, if we had available capacity, the prices at which we could otherwise sell the additional supply. Accordingly, any significant change in demand could have a material adverse effect on our results of operations and financial position.
We Are Subject to Financial Performance Risks Related to Regional and General Economic Cycles and also Related to Heavy Manufacturing Industries such as Automotive and Steel
Our business follows economic cycles. Economic conditions are a determinant of the demand for electricity and declines in the demand for electricity will reduce our revenues. The regional economy in which our Utilities operate is influenced by conditions in automotive, steel and other heavy industries and as these conditions change, our revenues will be impacted. Additionally, the primary market areas of our Competitive Energy Services segment overlap, to a large degree, with our Utilities' territories and hence its revenues are impacted by the same economic conditions.
Increases in Customer Electric Rates and Economic Uncertainty May Lead to a Greater Amount of Uncollectible Customer Accounts
Our operations are impacted by the economic conditions in our service territories and those conditions could negatively impact the rate of delinquent customer accounts and our collections of accounts receivable which could adversely impact our financial condition, results of operations and cash flows.
We May Recognize Impairments of Recorded Goodwill or of Some of Our Long-Lived Assets, Which Would Result in Write-Offs of the Impaired Amounts
Goodwill could become impaired at one or more of our operating subsidiaries. In addition, one or more of our long-lived assets could become impaired. The actual timing and amounts of any impairments in future years would depend on many factors, including interest rates, sector market performance, our capital structure, market prices for power, results of future rate proceedings, operating and capital expenditure requirements, the value of comparable acquisitions, environmental regulations and other factors.
We Face Certain Human Resource Risks Associated with the Availability of Trained and Qualified Labor to Meet Our Future Staffing Requirements
We must find ways to balance the retention of our aging skilled workforce while recruiting new talent to mitigate losses in critical knowledge and skills due to retirements. Mitigating these risks could require additional financial commitments.
Significant Increases in Our Operation and Maintenance Expenses, Including Our Health Care and Pension Costs, Could Adversely Affect Our Future Earnings and Liquidity
We continually focus on limiting, and reducing where possible, our operation and maintenance expenses. We expect to continue to face increased cost pressures in the areas of health care and pension costs. We have experienced significant health care cost inflation in the last few years, and we expect our cash outlay for health care costs, including prescription drug coverage, to continue to increase despite measures that we have taken and expect to take requiring employees and retirees to bear a higher portion of the costs of their health care benefits. The measurement of our expected future health care and pension obligations and costs is highly dependent on a variety of assumptions, many of which relate to factors beyond our control. These assumptions include investment returns, interest rates, health care cost trends, benefit design changes, salary increases, the demographics of plan participants and regulatory requirements. If actual results differ materially from our assumptions, our costs could be significantly increased.
Our Results May be Adversely Affected by the Volatility in Pension and OPEB Expenses.
Effective in 2011, FirstEnergy elected to change its method of recognizing actuarial gains and losses of its pension and OPEB plans. This change will result in the recognition of net actuarial gains or losses, without deferral, in the fourth quarter of each year and whenever a plan is determined to qualify for a remeasurement, may result in greater volatility in pension and OPEB expenses and may materially impact our results of operations under GAAP. For additional information, see Note 1, Organization, Basis of Presentation and Significant Accounting Policies of the Combined Notes to the Consolidated Financial Statements.
Security Breaches, Including Cyber Security Breaches, and Other Disruptions Could Compromise Critical and Proprietary Information and Expose Us to Liability, Which Would Cause our Business and Reputation to Suffer.
In the ordinary course of our business, we store sensitive data, intellectual property and proprietary information regarding our business, employees, customers, suppliers and business partners in our data centers and on our networks. The secure maintenance of this information is critical to our operations. Despite security measures we have employed with respect to this information, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings and regulatory penalties. It could also disrupt our business operations and damage our reputation, which could adversely affect our business.


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Acts of War or Terrorism Could Negatively Impact Our Business
The possibility that our infrastructure, such as electric generation, transmission and distribution facilities, or that of an interconnected company, could be direct targets of, or indirect casualties of, an act of war or terrorism, could result in disruption of our ability to generate, purchase, transmit or distribute electricity. Any such disruption could result in a decrease in revenues and additional costs to purchase electricity and to replace or repair our assets, which could have a material adverse impact on our results of operations and financial condition.
Capital Improvements and Construction Projects May Not be Completed Within Forecasted Budget, Schedule or Scope Parameters
Our business plan calls for extensive capital investments. We may be exposed to the risk of substantial price increases in the costs of labor and materials used in construction. We engage numerous contractors and enter into a large number of agreements to acquire the necessary materials and/or obtain the required construction-related services. As a result, we are also exposed to the risk that these contractors and other counterparties could breach their obligations to us. Such risk could include our contractors’ inabilities to procure sufficient skilled labor as well as potential work stoppages by that labor force. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices, with resulting delays in those and other projects. Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than these mitigation provisions. This could have negative financial impacts such as incurring losses or delays in completing construction projects.
Changes in Technology May Significantly Affect Our Generation Business by Making Our Generating Facilities Less Competitive
We primarily generate electricity at large central facilities. This method results in economies of scale and lower costs than newer technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells. It is possible that advances in technologies will reduce their costs to levels that are equal to or below that of most central station electricity production, which could have a material adverse effect on our results of operations.
We May Acquire Assets That Could Present Unanticipated Issues for Our Business in the Future, Which Could Adversely Affect Our Ability to Realize Anticipated Benefits of Those Acquisitions
Asset acquisitions involve a number of risks and challenges, including: management attention; integration with existing assets; difficulty in evaluating the requirements associated with the assets prior to acquisition, operating costs, potential environmental and other liabilities, and other factors beyond our control; and an increase in our expenses and working capital requirements. Any of these factors could adversely affect our ability to achieve anticipated levels of cash flows or realize other anticipated benefits from any such asset acquisition.
Ability of Certain FirstEnergy Companies to Meet Their Obligations to or on behalf of Other FirstEnergy Companies or their Affiliates
Certain of the FirstEnergy companies have obligations to other FirstEnergy companies because of transactions involving energy, coal, other commodities, services and hedging transactions. If one FirstEnergy entity failed to perform under any of these arrangements, other FirstEnergy entities could incur losses. Their results of operations, financial position, or liquidity could be adversely affected, resulting in the nondefaulting FirstEnergy entity being unable to meet its obligations to unrelated third parties. Our hedging activities are generally undertaken with a view to overall FirstEnergy exposures. Some FirstEnergy companies may therefore be more or less hedged than if they were to engage in such transactions alone. Also, some companies affiliated with FirstEnergy also provide guarantees to third party creditors on behalf of other FirstEnergy affiliates under transactions of the type described above or under financing transactions. Any failure to perform under such a guarantee by the affiliated FirstEnergy guarantor company or under the underlying transaction by the FirstEnergy company on whose behalf the guarantee was issued could have similar adverse impacts on one or both FirstEnergy companies or their affiliates.
Energy Companies are Subject to Adverse Publicity Which Make Them Vulnerable to Negative Regulatory and Legislative Outcomes

Energy companies, including FirstEnergy's utility subsidiaries, have been the subject of criticism focused on the reliability of their distribution services and the speed with which they are able to respond to power outages, such as those caused by storm damage. Adverse publicity of this nature, or adverse publicity associated with our nuclear and/or coal-fired facilities may cause less favorable legislative and regulatory outcomes.
Our Merger with AE May Not Achieve Its Intended Results.

We entered into the merger agreement with AE with the expectation that the merger would result in various benefits, including, among other things, cost savings and operating efficiencies relating to the regulated business and the unregulated competitive business. Our ability to achieve the anticipated benefits of the merger is subject to a number of uncertainties, including whether the business and information systems of Allegheny are integrated in an efficient and effective manner. Failure to achieve these anticipated benefits could result in increased costs, decreases in the amount of expected revenues generated by us and diversion of management's time and energy and could have an adverse effect on our business, financial results and prospects. See Part II, Item 7, Management's Discussion and Analysis of Registrant and Subsidiaries for additional information.


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Risks Associated With Regulation
Complex and Changing Government Regulations, Including Those Associated With Rates Could Have a Negative Impact on Our Results of Operations
We are subject to comprehensive regulation by various federal, state and local regulatory agencies that significantly influence our operating environment. Changes in, or reinterpretations of, existing laws or regulations, or the imposition of new laws or regulations, could require us to incur additional costs or change the way we conduct our business, and therefore could have an adverse impact on our results of operations.
Our utility subsidiaries currently provide service at rates approved by one or more regulatory commissions. Thus, the rates a utility is allowed to charge may or may not be set to recover its expenses at any given time. Additionally, there may also be a delay between the timing of when costs are incurred and when costs are recovered. For example, we may be unable to timely recover the costs for our energy efficiency investments, expenses and additional capital or lost revenues resulting from the implementation of aggressive energy efficiency programs. While rate regulation is premised on providing an opportunity to earn a reasonable return on invested capital and recovery of operating expenses, there can be no assurance that the applicable regulatory commission will determine that all of our costs have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs in a timely manner.
Regulatory Changes in the Electric Industry, Including a Reversal of, Discontinuance of, or Impediment to the Present Trend Toward Competitive Markets, Could Affect Our Competitive Position and Result in Unrecoverable Costs Adversely Affecting Our Business and Results of Operations
As a result of restructuring initiatives, changes in the electric utility business have occurred, and are continuing to take place throughout the United States, including the states in which we do business. These changes have resulted, and are expected to continue to result, in fundamental alterations in the way utilities conduct their business.
Some states that have deregulated generation service have experienced difficulty in transitioning to market-based pricing. In some instances, state and federal government agencies and other interested parties have made proposals to impose rate cap extensions or otherwise impede market restructuring or even re-regulate areas of these markets that have previously been deregulated. Although we expect wholesale electricity markets to continue to be competitive, proposals to re-regulate our industry may be made, and legislative or other action affecting the electric power restructuring process may cause the process to be delayed, discontinued, restructured or reversed in the states in which we currently, or may in the future, operate. Such delays, discontinuations or reversals of electricity market restructuring in the markets in which we operate could have an adverse impact on our results of operations and financial condition.
The FERC and the U.S. Congress propose changes from time to time in the structure and conduct of the electric utility industry. If the restructuring, deregulation or re-regulation efforts result in decreased margins or unrecoverable costs, our business and results of operations would be adversely affected. We cannot predict the extent or timing of further efforts to restructure, deregulate or re-regulate our business or the industry.
The Prospect of Rising Rates Could Prompt Legislative or Regulatory Action to Restrict or Control Such Rate Increases. This In Turn Could Create Uncertainty Affecting Planning, Costs and Results of Operations and May Adversely Affect the Utilities’ Ability to Recover Their Costs, Maintain Adequate Liquidity and Address Capital Requirements
Increases in utility rates, such as may follow a period of frozen or capped rates, can generate pressure on legislators and regulators to take steps to control those increases. Such efforts can include some form of rate increase moderation, reduction or freeze. The public discourse and debate can increase uncertainty associated with the regulatory process, the level of rates and revenues, and the ability to recover costs. Such uncertainty restricts flexibility and resources, given the need to plan and ensure available financial resources. Such uncertainty also affects the costs of doing business. Such costs could ultimately reduce liquidity, as suppliers tighten payment terms, and increase costs of financing, as lenders demand increased compensation or collateral security to accept such risks.
Our Profitability is Impacted by Our Affiliated Companies’ Continued Authorization to Sell Power at Market-Based Rates
The FERC granted certain subsidiaries authority to sell electricity at market-based rates. These orders also granted them waivers of certain FERC accounting, record-keeping and reporting requirements. The FERC’s orders that grant this market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that these companies can exercise market power in transmission or generation, create barriers to entry or engage in abusive affiliate transactions. As a condition to the orders granting the generating companies market-based rate authority, every three years they are required to file a market power update to show that they continue to meet the FERC’s standards with respect to generation market power and other criteria used to evaluate whether entities qualify for market-based rates.
There Are Uncertainties Relating to Our Participation in RTOs
RTO rules could affect our ability to sell power produced by our generating facilities to users in certain markets due to transmission


34


constraints and attendant congestion costs. The prices in day-ahead and real-time energy markets and RTO capacity markets have been subject to price volatility. Administrative costs imposed by RTOs, including the cost of administering energy markets, have also increased. The rules governing the various regional power markets may also change from time to time, which could affect our costs or revenues. To the degree we incur significant additional fees and increased costs to participate in an RTO, and we are limited with respect to recovery of such costs from retail customers, we may suffer financial harm. In addition, we may be allocated a portion of the cost of transmission facilities built by others due to changes in RTO transmission rate design. Finally, we may be required to expand our transmission system according to decisions made by an RTO rather than our internal planning process. As a member of an RTO, we are subject to certain additional risks, including those associated with the allocation among members of losses caused by unreimbursed defaults of other participants in that RTO’s market and those associated with complaint cases filed against the RTO that may seek refunds of revenues previously earned by its members.
Because it remains unclear which companies will be participating in the various regional power markets, or how RTOs will ultimately develop and operate, or what region they will cover, we cannot fully assess the impact that these power markets or other ongoing RTO developments may have.
Energy Conservation and Energy Price Increases Could Negatively Impact Our Financial Results
A number of regulatory and legislative bodies have introduced requirements and/or incentives to reduce energy consumption. Conservation programs could impact our financial results in different ways. To the extent conservation resulted in reduced energy demand or significantly slowed the growth in demand, the value of our competitive generation and other unregulated business activities could be adversely impacted. We currently have energy efficiency riders in place to recover the cost of these programs either at or near a current recovery timeframe in the states we operate. In New Jersey, we recover the costs for energy efficiency programs through the SBC. Currently only Ohio has provisions for recovery of lost revenues. In our regulated operations, conservation could negatively impact us depending on the regulatory treatment of the associated impacts. Should we be required to invest in conservation measures that result in reduced sales from effective conservation, regulatory lag in adjusting rates for the impact of these measures could have a negative financial impact. We could also be impacted if any future energy price increases result in a decrease in customer usage. Our results could be affected if we are unable to increase our customer’s participation in our energy efficiency programs. We are unable to determine what impact, if any, conservation and increases in energy prices will have on our financial condition or results of operations.
Our Business and Activities are Subject to Extensive Environmental Requirements and Could be Adversely Affected by such Requirements
We plan to retire nine older coal-fired generating plants by September 1, 2012, as a result of a comprehensive review of FirstEnergy's coal-fired generating facilities in light of the MATS rules that were recently finalized and other environmental requirements. We may be forced to shut down other facilities, either temporarily or permanently, if we are unable to comply with certain environmental requirements, or if we make a determination that the expenditures required to comply with such requirements are uneconomical.
The EPA is Conducting NSR Investigations at a Number of Generating Plants that We Currently or Formerly Owned, the Results of Which Could Negatively Impact Our Results of Operations and Financial Condition
We may be subject to risks in connection with changing or conflicting interpretations of existing laws and regulations, including, for example, the applicability of EPA's NSR programs . Under the CAA, modification of our generation facilities in a manner that results in increased emissions could subject our existing facilities to the far more stringent NSR standards applicable to new facilities.
The EPA has taken the view that many companies, including many energy producers, have been modifying emissions sources in violation of NSR standards in connection with work considered by the companies to be routine maintenance. We are currently involved in litigation and EPA investigations concerning alleged violations of the NSR standards at certain of our existing and former generating facilities. We intend to vigorously pursue and defend our position but we are unable to predict their outcomes. If NSR and similar requirements are imposed on our generation facilities, in addition to the possible imposition of fines, compliance could entail significant capital investments in pollution control technology, which could have an adverse impact on our business, results of operations, cash flows and financial condition. For a more complete discussion see Note 16, Commitments, Guarantees and Contingencies - Environmental Matters of the Combined Notes to the Consolidated Financial Statements.
Costs of Compliance with Environmental Laws are Significant, and the Cost of Compliance with Future Environmental Laws, Including Limitations on GHGEmissions, Could Adversely Affect Cash Flow and Profitability

Our operations are subject to extensive federal, state and local environmental statutes, rules and regulations. Compliance with these legal requirements requires us to incur costs for among other things, installation and operation of pollution control equipment, emission monitoring and fees, remediation and permitting at our facilities. These expenditures have been significant in the past and may increase in the future. If the cost of compliance with existing environmental laws and regulations does increase, it could adversely affect our business and results of operations, financial position and cash flows. Moreover, new environmental laws or regulations or changes to existing environmental laws or regulations may materially increase our costs of compliance or accelerate the timing of capital expenditures. Because of the deregulation of generation, we may not directly recover through rates additional costs incurred for such compliance. Our compliance strategy, although reasonably based on available information, may not successfully address future relevant standards and interpretations. If we fail to comply with environmental laws and regulations or


35


new interpretations of longstanding requirements, even if caused by factors beyond our control, that failure could result in the assessment of civil or criminal liability and fines. In addition, any alleged violation of environmental laws and regulations may require us to expend significant resources to defend against any such alleged violations.

There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. Environmental advocacy groups, other organizations and some agencies in the United States and elsewhere are focusing considerable attention on carbon dioxide emissions from power generation facilities and their potential role in climate change. There is a growing consensus in the United States and globally that GHG emissions are a major cause of global warming and that some form of regulation will be forthcoming at the federal level with respect to GHG emissions (including CO2) and such regulation could result in the creation of substantial additional costs in the form of taxes or emission allowances. As a result, it is possible that state and federal regulations will be developed that will impose more stringent limitations on emissions than are currently in effect. Due to the uncertainty of control technologies available to reduce GHG emissions, including CO2, as well as the unknown nature of potential compliance obligations should climate change regulations be enacted, we cannot provide any assurance regarding the potential impacts these future regulations would have on our operations. In addition, any legal obligation that would require us to substantially reduce our emissions could require extensive mitigation efforts and, in the case of carbon dioxide legislation, would raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities. Until specific regulations are issued, the impact that any new environmental regulations, voluntary compliance guidelines, enforcement initiatives, or legislation may have on our results of operations, financial condition or liquidity is not determinable.

FirstEnergy cannot currently estimate the financial impact of certain environmental laws or initiatives including climate change policies, but 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. See Note 16, Commitments, Guarantees and Contingencies - Environmental Matters of the Combined Notes to the Consolidated Financial Statements for a more detailed discussion of the federal, state and international initiatives seeking to reduce emissions of GHG.

We Could be Exposed to Private Rights of Action Seeking Damages Under Various State and Federal Law Theories

Claims have been made against certain energy companies alleging that CO2 emissions from power generating facilities constitute a public nuisance under federal and/or state common law. As a result, private individuals may seek to enforce environmental laws and regulations against us and could allege personal injury or property damages. While FirstEnergy is not a party to this litigation, it, and/or one of its subsidiaries, could be named in actions making similar allegations. An unfavorable ruling in any such case could have an adverse impact on our results of operations and financial condition and could significantly impact our operations.

Our Costs to Comply with Various Recently Adopted EPA Emission Regulations Could be Substantial and Result in Significant Changes to Our Operations

We are required to comply with recently adopted emission regulations. The EPA's CAIR and CSAPR require reductions of NOx and SO2 emissions in two phases, ultimately capping SO2 and NOx emissions in affected states. In July 2011, the EPA finalized the CSAPR (which was stayed in December 2011 pending a decision on various legal challenges) to replace CAIR, which remains in effect until CSAPR becomes effective.

Depending on the outcome of these legal proceedings and how any final rules are ultimately implemented, MP's, FGCO's and AE Supply's future cost of compliance may be substantial and changes to FirstEnergy's operations may result.

Additionally, on December 21, 2011, the EPA finalized the MATS to establish emission standards for, among other things, mercury, hydrochloric acid and various metals for electric generating units. The costs associated with MATS, and other environmental laws, is substantial and led to the Company's recent announcement to retire nine older coal-fired generating units. Depending on how the CSPAR and MATS are ultimately implemented, FirstEnergy's future cost of compliance with such regulations may be substantial and additional changes to FirstEnergy's operations may result. See Note 16, Commitments, Guarantees and Contingencies - Environmental Matters of the Combined Notes to the Consolidated Financial Statements for a more detailed discussion of the above-referenced EPA regulations.

Various Federal and State Water Quality Regulations May Require Us to Make Material Capital Expenditures

The EPA established performance standards under the Clean Water Act which requires the EPA to establish performance standards for reducing impacts on fish and shellfish from cooling water intake structures at certain existing electric generating plants, specifically, impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). In 2011, the EPA proposed new regulations under the Clean Water Act which generally require fish impingement to be reduced to a 12% annual average and calls for studies to be conducted at the majority of our existing generating facilities to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic life. FirstEnergy is studying the cost and effectiveness of various control options to divert fish away from its plants' cooling water intake system. Depending on the results of such studies and the EPA's further rulemaking and any final action taken by the states, the future costs of compliance with these standards may require material capital expenditures. See Note 16, Commitments, Guarantees and Contingencies - Environmental Matters of the Combined Notes to the Consolidated Financial Statements for a more detailed discussion of the various federal and state water


36


quality regulations listed above.

Compliance with any Coal Combustion Residual Regulations Could Have an Adverse Impact on Our Results of Operations and Financial Condition

We are subject to various federal and state hazardous waste regulations. The EPA has requested comments from the states on options for regulating coal combustion residuals, including whether they should be regulated as hazardous or non-hazardous waste.

The EPA asserted that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry and has proposed two options for additional regulation of coal combustion residuals, including the option of regulation as a special waste under the EPA's hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. FirstEnergy's future cost of compliance with any coal combustion residuals regulations that may be issued could be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the EPA or the states. Compliance with those regulations could have an adverse impact on our results of operations and financial condition.
Remediation of Environmental Contamination at Current or Formerly Owned Facilities
We are subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we may have generated regardless of whether the liabilities arose before, during or after the time we owned or operated the facilities. Remediation activities associated with our former MGP operations are one source of such costs. We are currently involved in a number of proceedings relating to sites where other hazardous substances have been deposited and may be subject to additional proceedings in the future. We also have current or previous ownership interests in sites associated with the production of gas and the production and delivery of electricity for which we may be liable for additional costs related to investigation, remediation and monitoring of these sites. Citizen groups or others may bring litigation over environmental issues including claims of various types, such as property damage, personal injury, and citizen challenges to compliance decisions on the enforcement of environmental requirements, such as opacity and other air quality standards, which could subject us to penalties, injunctive relief and the cost of litigation. We cannot predict the amount and timing of all future expenditures (including the potential or magnitude of fines or penalties) related to such environmental matters, although we expect that they could be material.
In some cases, a third party who has acquired assets from us has assumed the liability we may otherwise have for environmental matters related to the transferred property. If the transferee fails to discharge the assumed liability or disputes its responsibility, a regulatory authority or injured person could attempt to hold us responsible, and our remedies against the transferee may be limited by the financial resources of the transferee.
We Are and May Become Subject to Legal Claims Arising from the Presence of Asbestos or Other Regulated Substances at Some of Our Facilities
We have been named as a defendant in pending asbestos litigation involving multiple plaintiffs and multiple defendants. In addition, asbestos and other regulated substances are, and may continue to be, present at our facilities where suitable alternative materials are not available. We believe that any remaining asbestos at our facilities is contained. The continued presence of asbestos and other regulated substances at these facilities, however, could result in additional actions being brought against us.
Availability and Cost of Emission Allowances Could Negatively Impact Our Costs of Operations

Although recent court rulings and current conditions have reduced the immediate risk of a negative impact on our operating costs, the uncertainty around CAA programs and requirements continue to be a major concern. We are still required to maintain, either by allocation or purchase, sufficient emission allowances to support our operations in the ordinary course of operating our power generation facilities. These allowances are used to meet our obligations imposed by various applicable environmental laws. If our operational needs require more than our allocated allowances, we may be forced to purchase such allowances on the open market, which could be costly. If we are unable to maintain sufficient emission allowances to match our operational needs, we may have to curtail our operations so as not to exceed our available emission allowances, or install costly new emissions controls. As we use the emissions allowances that we have purchased on the open market, costs associated with such purchases will be recognized as operating expense. If such allowances are available for purchase, but only at significantly higher prices, the purchase of such allowances could materially increase our costs of operations in the affected markets.
Mandatory Renewable Portfolio Requirements Could Negatively Affect Our Costs
If federal or state legislation mandates the use of renewable and alternative fuel sources, such as wind, solar, biomass and geothermal and such legislation would not also provide for adequate cost recovery, it could result in significant changes in our business, including renewable energy credit purchase costs, purchased power and potentially renewable energy credit costs and capital expenditures. We are unable to predict what impact, if any, these changes may have on our financial condition or results of operations.
The Continuing Availability and Operation of Generating Units is Dependent on Retaining or Renewing the Necessary Licenses, Permits, and Operating Authority from Governmental Entities, Including the NRC


37


We are required to have numerous permits, approvals and certificates from the agencies that regulate our business. We believe the necessary permits, approvals and certificates have been obtained for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from future regulatory activities of any of these agencies and we are not assured that any such permits, approvals or certifications will be renewed.
Potential NRC Regulation in Response to the Incident at Japan's Fukushima Daiichi Nuclear Plant Could Adversely Effect Our Business and Financial Condition

As a result of the NRC's investigation of the incident at the Fukushima Daiichi nuclear plant, potential exists for the NRC to promulgate new or revised requirements with respect to nuclear plants located in the United States, which could necessitate additional expenditures at our nuclear plants. For example, as a follow up to the NRC near-term Task Force's review and analysis of the Fukushima Daiichi accident, in January 2012, the NRC released an updated seismic risk model that plant operators must use in performing the seismic reevaluations recommended by the task force. These reevaluations could result in the required implementation of additional mitigation strategies or modifications. It is also possible that the NRC could suspend or otherwise delay pending nuclear relicensing proceedings, including the Davis-Besse relicensing proceeding. The impact of any such regulatory actions could adversely affect FirstEnergy's financial condition or results of operations.
The Physical Risks Associated with Climate Change May Impact Our Results of Operations and Cash Flows
Physical risks of climate change, such as more frequent or more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, and other related phenomena, could affect some, or all, of our operations. Severe weather or other natural disasters could be destructive, which could result in increased costs, including supply chain costs. An extreme weather event within the Utilities' service areas can also directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment. Finally, climate change could affect the availability of a secure and economical supply of water in some locations, which is essential for continued operation of generating plants.
Future Changes in Accounting Standards May Affect Our Reported Financial Results
The SEC, FASB or other authoritative bodies or governmental entities may issue new pronouncements or new interpretations of existing accounting standards that may require us to change our accounting policies. These changes are beyond our control, can be difficult to predict and could materially impact how we report our financial condition and results of operations. We could be required to apply a new or revised standard retroactively, which could adversely affect our financial position. The SEC announced a work plan to aid in its evaluation of the impact that the use of IFRS by U.S. public companies would have on the U.S. securities market and has identified several potential options to incorporate IFRS in the United States. The SEC expects to announce a more specific course of action in 2012. We continue to monitor the development of the potential implementation of IFRS.
Increases in Taxes and Fees May Adversely Effect Our Results of Operation, Financial Audit and Cash Flow
Due to the revenue needs of the United States and the states and jurisdictions in which we operate, various tax and fee increases may be proposed or considered. We cannot predict whether legislation or regulation will be introduced, the form of any legislation or regulation, whether any such legislation or regulation will be passed by legislatures or regulatory bodies. If enacted, these changes could increase tax costs and could have a negative impact on our results of operations, financial condition and cash flows.
Risks Associated With Financing and Capital Structure
Disruptions in the Capital and Credit Markets May Adversely Affect Our Business, Including the Availability and Cost of Short-Term Funds for Liquidity Requirements, Our Ability to Meet Long-Term Commitments, Our Ability to Hedge Effectively Our Generation Portfolio, and the Competitiveness and Liquidity of Energy Markets; Each Could Adversely Affect Our Results of Operations, Cash Flows and Financial Condition
We rely on the capital markets to meet our financial commitments and short-term liquidity needs if internal funds are not available from our operations. We also use letters of credit provided by various financial institutions to support our hedging operations. Disruptions in the capital and credit markets could adversely affect our ability to draw on our respective credit facilities. Our access to funds under those credit facilities is dependent on the ability of the financial institutions that are parties to the facilities to meet their funding commitments. Those institutions may not be able to meet their funding commitments if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests within a short period of time.
Longer-term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant financial institutions could adversely affect our access to liquidity needed for our business. Any disruption could require us to take measures to conserve cash until the markets stabilize or until alternative credit arrangements or other funding for our business needs can be arranged. Such measures could include deferring capital expenditures, changing hedging strategies to reduce collateral-posting requirements, and reducing or eliminating future dividend payments or other discretionary uses of cash.
The strength and depth of competition in energy markets depends heavily on active participation by multiple counterparties, which


38


could be adversely affected by disruptions in the capital and credit markets. Reduced capital and liquidity and failures of significant institutions that participate in the energy markets could diminish the liquidity and competitiveness of energy markets that are important to our business. Perceived weaknesses in the competitive strength of the energy markets could lead to pressures for greater regulation of those markets or attempts to replace those market structures with other mechanisms for the sale of power, including the requirement of long-term contracts, which could have a material adverse effect on our results of operations and cash flows.
Interest Rates and/or a Credit Rating Downgrade Could Negatively Affect Our Financing Costs, Our Ability to Access Capital and Our Requirement to Post Collateral
We have near-term exposure to interest rates from outstanding indebtedness indexed to variable interest rates, and we have exposure to future interest rates to the extent we seek to raise debt in the capital markets to meet maturing debt obligations and fund construction or other investment opportunities. Past disruptions in capital and credit markets have resulted in higher interest rates on new publicly issued debt securities, increased costs for certain of our variable interest rate debt securities and failed remarketings of variable interest rate tax-exempt debt issued to finance certain of our facilities. Similar future disruptions could increase our financing costs and adversely affect our results of operations. Also, interest rates could change as a result of economic or other events that our risk management processes were not established to address. As a result, we cannot always predict the impact that our risk management decisions may have on us if actual events lead to greater losses or costs than our risk management positions were intended to hedge. Although we employ risk management techniques to hedge against interest rate volatility, significant and sustained increases in market interest rates could materially increase our financing costs and negatively impact our reported results of operations.
We rely on access to bank and capital markets as sources of liquidity for cash requirements not satisfied by cash from operations. A downgrade in our credit ratings from the nationally recognized credit rating agencies, particularly to a level below investment grade, could negatively affect our ability to access the bank and capital markets, especially in a time of uncertainty in either of those markets, and may require us to post cash collateral to support outstanding commodity positions in the wholesale market, as well as available letters of credit and other guarantees. Furthermore, a downgrade could increase the cost of such capital by causing us to incur higher interest rates and fees associated with such capital. A rating downgrade would also increase the fees we pay on our various existing credit facilities, thus increasing the cost of our working capital. A rating downgrade could also impact our ability to grow our businesses by substantially increasing the cost of, or limiting access to, capital. See Note 16, Commitments, Guarantees and Contingencies - Guarantees and Other Assurances of the Combined Notes to the Consolidated Financial Statements for more information associated with a credit ratings downgrade leading to the posting of cash collateral.
The Soundness of Financial Institutions or Counterparties Could Adversely Affect Us
We have exposure to many different domestic and foreign financial institutions and counterparties and we routinely execute transactions with counterparties in connection with our hedging activities, including brokers and dealers, commercial banks, investment banks and other institutions and industry participants. Many of these transactions expose us to credit risk in the event that any of our lenders or counterparties are unable to honor their commitments or otherwise default under a financing agreement. We also deposit cash balances in short-term investments. Our ability to access our cash quickly depends on the soundness of the financial institutions in which those funds reside. Any delay in our ability to access those funds, even for a short period of time, could have a material adverse effect on our results of operations and financial condition.
We Must Rely on Cash from Our Subsidiaries and Any Restrictions on Our Utility Subsidiaries' Ability to Pay Dividends or Make Cash Payments to Us May Adversely Affect Our Financial Condition
We are a holding company and our investments in our subsidiaries are our primary assets. Substantially all of our business is conducted by our subsidiaries. Consequently, our cash flow is dependent on the operating cash flows of our subsidiaries and their ability to upstream cash to the holding company. Our utility subsidiaries are regulated by various state utility commissions that generally possess broad powers to ensure that the needs of utility customers are being met. Those state commissions could attempt to impose restrictions on the ability of our utility subsidiaries to pay dividends or otherwise restrict cash payments to us.
We Cannot Assure Common Shareholders that Future Dividend Payments Will be Made, or if Made, in What Amounts they May be Paid

Our Board of Directors regularly evaluates our common stock dividend policy and determines the dividend rate each quarter. The level of dividends will continue to be influenced by many factors, including, among other things, our earnings, financial condition and cash flows from subsidiaries, as well as general economic and competitive conditions. We cannot assure common shareholders that dividends will be paid in the future, or that, if paid, dividends will be at the same amount or with the same frequency as in the past.
ITEM 1B.UNRESOLVED STAFF COMMENTS
None.


39


ITEM 2.PROPERTIES
The Ohio Companies', Penn's, FGCO’s and NGC’s respective first mortgage indentures constitute direct first liens on substantially all of the respective physical property, subject only to excepted encumbrances, as defined in the first mortgage indentures. See Notes 6, Leases, and 12, Capitalization of the Combined Notes to the Consolidated Financial Statements for information concerning leases and financing encumbrances affecting certain of the Utilities’, FGCO’s and NGC’s properties.
FirstEnergy controls the following generation sources as of January 31, 2012, shown in the table below. Except for the leasehold interests, OVEC participation and wind power arrangements referenced in the footnotes to the table, substantially all FES' competitive generating units are owned by NGC (nuclear) and FGCO (non-nuclear); the regulated generating units are owned by JCP&L and MP.


40


      Competitive  
Plant (Location) Unit Total FES AE Supply Regulated
    Net Demonstrated Capacity (MW)
Super-critical Coal-fired:  
        
Bruce Mansfield (Shippingport, PA) 1
 830
(1) 
830
 —
 —
Bruce Mansfield (Shippingport, PA) 2
 830
(2) 
830
 —
 —
Bruce Mansfield (Shippingport, PA) 3
 830
(3) 
830
 —
 —
Harrison (Haywood, WV) 1-3
 1,984
 —
 1,576
 408
Hatfield's Ferry (Masontown, PA) 1-3
 1,710
 —
 1,710
 —
Pleasants (Willow Island, WV) 1-2
 1,300
 —
 1,200
 100
W. H. Sammis (Stratton, OH) 6-7
 1,200
  
1,200
 —
 —
Fort Martin (Maidsville, WV) 1-2
 1,107
 —
 —
 1,107
Eastlake (Eastlake, OH)(4)
 5
 597
 597
 —
 —
    10,388
 4,287
 4,486
 1,615
Sub-critical and Other Coal-fired:          
W. H. Sammis (Stratton, OH) 1-5
 1,020
  
1,020
 —
 —
Eastlake (Eastlake, OH)(4)
 1-4
 636
 636
 —
 —
Bay Shore (Toledo, OH) 1
 136
 136
    
Bay Shore (Toledo, OH)(4)
 2-4
 495
 495
 —
 —
Armstrong (Adrian, PA)(4)
 1-2
 356
 —
 356
 —
Albright (Albright, WV)(4)
 1-3
 292
 —
 —
 292
Mitchell (Courtney, PA) 3
 288
 —
 288
 —
Lakeshore (Cleveland, OH)(4)
 18
 245
 245
 —
 —
Ashtabula (Ashtabula, OH)(4)
 5
 244
 244
 —
 —
Willow Island (Willow Island, WV)(4)
 1-2
 242
 —
 —
 242
Rivesville (Rivesville, WV)(4)
 5-6
 126
 —
 —
 126
R. Paul Smith (Williamsport, MD)(4)
 3-4
 116
 —
 116
 —
R. E. Burger (Shadyside, OH) 3
 94
 94
 —
 —
OVEC (Cheshire, OH) (Madison, IN) 1-11
 188
(5) 
110
 67
 11
   
 4,478
  
2,980
 827
 671
Nuclear:  
  
  
     
Beaver Valley (Shippingport, PA) 1
 911
  
911
 —
 —
Beaver Valley (Shippingport, PA) 2
 904
(6) 
904
 —
 —
Davis-Besse (Oak Harbor, OH) 1
 908
  
908
 —
 —
Perry (N. Perry Village, OH) 1
 1,268
(7) 
1,268
 —
 —
   
 3,991
  
3,991
 —
 —
Gas/Oil-fired:  
  
  
     
AE Nos. 1, 2, 3, 4 & 5 (Springdale, PA) 1-5
 638
 —
 638
 —
West Lorain (Lorain, OH) 1-6
 545
  
—
 545
 —
AE Nos. 12 & 13 (Chambersburg, PA) 12-13
 88
 —
 88
 —
AE Nos. 8 & 9 (Gans, PA) 8-9
 88
 —
 88
 —
Mitchell (Courtney, PA) 2
 82
 —
 82
 —
Hunlock CT (Hunlock Creek, PA) 1
 45
 —
 45
 —
Buchanan (Oakwood, VA) 1-2
 43
(8) 
—
 43
 —
Other   216
 216
 —
 —
    1,745
 216
 1,529
 —
Pumped-storage and Hydro:  
  
  
     
Bath County (Warm Springs, VA) 1-6
 1,110
(9) 
—
 660
 450
Seneca (Warren, PA) 1-3
 451
  
451
 —
 —
Yard’s Creek (Blairstown Twp., NJ) 1-3
 200
(10) 
—
 —
 200
Lake Lynn (Lake Lynn, PA) 1-4
 52
(11) 
—
 52
  
Other   19
 —
 19
 —
    1,832
 451
 731
 650
Wind Power  
 376
(12) 
376
 —
 —
Total   22,810
 12,301
 7,573
 2,936


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(1)
Includes FGCO’s leasehold interest of 93.825% (779 MW) and CEI’s leasehold interest of 6.175% (51 MW), which has been assigned to FGCO.
(2)
Includes CEI’s and TE’s leasehold interests of 27.17% (226 MW) and 16.435% (136 MW), respectively, which have been assigned to FGCO.
(3)
Includes CEI’s and TE’s leasehold interests of 23.247% (193 MW) and 18.915% (157 MW), respectively, which have been assigned to FGCO.
(4)
During the first quarter of 2012, FirstEnergy announced that these coal-fired plants will be retired by September 1, 2012, subject to review for reliability impacts by PJM.
(5)
Represents FGCO’s 4.85% and AE's 3.5% entitlement based on their participation in OVEC.
(6)
Includes OE’s leasehold interest of 16.65% (151 MW) from non-affiliates.
(7)
Includes OE’s leasehold interest of 8.11% (103 MW) from non-affiliates.
(8)
Buchanan Energy is a subsidiary of AE Supply. CNX Gas Corporation and Buchanan Energy have equal ownership interests in Buchanan Generation, LLC. AE Supply operates and dispatches 100% of Buchanan Generation, LLC's 86 MWs.
(9)
Represents capacity entitlement through ownership of AGC.
(10)
Represents JCP&L’s 50% ownership interest.
(11)
AE Supply has a license for Lake Lynn through 2024.
(12)
Includes 167 MW from leased facilities and 209 MW under power purchase agreements.
The above generating plants and load centers are connected by a transmission system consisting of elements having various voltage ratings ranging from 23 kV to 500 kV. The Utilities’ overhead and underground transmission lines aggregate 24,305 pole miles.
The Utilities’ electric distribution systems include 254,899 miles of overhead pole line and underground conduit carrying primary, secondary and street lighting circuits. They own substations with a total installed transformer capacity of approximately 140,158,000 kV-amperes.
All of FirstEnergy's generation, transmission and distribution assets operate in PJM.
FirstEnergy’s distribution and transmission systems as of December 31, 2011, consist of the following:
 
Distribution
Lines(1)
 
Transmission
Lines(1)
 
Substation
Transformer
Capacity(2)
   kV Amperes
OE62,238
 461
 7,763,000
Penn13,419
 52
 1,425,000
CEI33,252
 —
 8,938,000
TE17,593
 81
 3,040,000
JCP&L22,800
 2,550
 23,150,000
Met-Ed18,695
 1,406
 10,819,000
Penelec27,131
 2,909
 15,234,000
ATSI(3)
—
 7,524
 23,578,000
WP20,026
 4,419
 14,077,000
MP20,730
 2,625
 15,230,000
PE19,015
 2,126
 11,033,000
TrAIL(4)
—
 152
 5,871,000
Total254,899
 24,305
 140,158,000
(1)
Pole miles
(2)
Top rating of in-service power transformers only. Excludes grounding banks, station power transformers, and generator and customer-owned transformers.
(3)
Represents transmission lines of 69kV and above located in the service areas of OE, Penn, CEI and TE.
(4)
Represents transmission lines at 500kV located in the service areas of MP, PE and WP.
ITEM 3.LEGAL PROCEEDINGS
Reference is made to Note 16, Commitments, Guarantees and Contingencies of the Combined Notes to the Consolidated Financial Statements for a description of certain legal proceedings involving FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec.
ITEM 4.MINE SAFETY DISCLOSURE
Signal Peak Mine Safety
During 2011, FirstEnergy, through its FEV wholly owned subsidiary, held a 50% interest in Global Mining Group, LLC, a joint venture owning Signal Peak, which is a company that constructed and operates the Bull Mountain Mine No. 1 (Mine), an underground coal mine near Roundup Montana. The operation of the Mine is subject to regulation by the MSHA under the Mine Act.


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On October 18, 2011, FirstEnergy announced that Gunvor Group, Ltd. signed an agreement to purchase a one-third interest in the Signal Peak coal mine in Montana. As a result of the sale, FirstEnergy, through its wholly owned subsidiary, FEV, currently has a 33-1/3% interest in Global Holding, a joint venture that owns Signal Peak.
Information concerning mine safety violations or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act is included in Exhibit 95 to this Annual Report on Form 10-K.
PART II
ITEM 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
The information required by Item 5 regarding FirstEnergy’s market information, including stock exchange listings and quarterly stock market prices, dividends and holders of common stock is included in Item 6.
Information for FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec is not disclosed because they are wholly owned subsidiaries of FirstEnergy and there is no market for their common stock.
Information regarding compensation plans for which shares of FirstEnergy common stock may be issued is incorporated herein by reference to FirstEnergy’s 2012 proxy statement to be filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.
The table below includes information on a monthly basis regarding purchases made by FE of its common stock during the fourth quarter of 2011.
  Period
  October November December Fourth Quarter
Total Number of Shares Purchased(1)
 112,225
 167,674
 712,539
 992,438
Average Price Paid per Share $44.36
 $44.32
 $44.19
 $44.23
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 —
 —
 —
 —
(1)
Share amounts reflect purchases on the open market to satisfy FirstEnergy's obligations to deliver common stock for some or all of the following: 2007 Incentive Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan, Director Compensation, Allegheny Energy, Inc. 1998 Long-Term Incentive Plan, Allegheny Energy, Inc. 2008 Long-Term Incentive Plan, Allegheny Energy, Inc, Non-Employee Director Stock Plan, Allegheny Energy, Inc, Amended and Restated Revised Plan for Deferral of Compensation of Directors, and Stock Investment Plan.
ITEM 6.SELECTED FINANCIAL DATA
For the Years Ended December 31, 2011 
2010(1)
 
2009(1)
 
2008(1)
 
2007(1)
  (In millions, except per share amounts)
Revenues $16,258
 $13,339
 $12,973
 $13,627
 $12,802
Earnings Available to FirstEnergy Corp.(2)
 $885
 $742
 $872
 $623
 $1,489
Earnings per Share of Common Stock:(2)
          
Basic $2.22
 $2.44
 $2.87
 $2.05
 $4.86
Diluted $2.21
 $2.42
 $2.85
 $2.03
 $4.80
Weighted Average Shares Outstanding:          
Basic 399
 304
 304
 304
 306
Diluted 401
 305
 306
 307
 310
Dividends Declared per Share of Common Stock(3)
 $2.20
 $2.20
 $2.20
 $2.20
 $2.05
Total Assets(4)
 $47,326
 $35,531
 $35,054
 $34,206
 $32,394
Capitalization as of December 31:          
Total Equity(5)
 $13,299
 $8,952
 $9,014
 $8,748
 $9,129
Long-Term Debt and Other Long-Term Obligations 15,716
 12,579
 12,008
 9,100
 8,869
Total Capitalization(5)
 $29,015
 $21,531
 $21,022
 $17,848
 $17,998
(1)
Reflects the retrospective change in recognizing pensions and OPEB costs.
(2)
The retrospective change in accounting for pensions and OPEB costs decreased Earnings Available to FirstEnergy Corp and Earnings Per Share (basic; diluted) as follows: 2010 - $42 million ($0.14; $0.15 per share), 2009 - $134 million ($0.44; $0.44 per share) and 2008 - $719


43


million ($2.36; $2.35 per share); and increased Earnings Available to FirstEnergy Corp. and Earnings Per Share (basic; diluted) in 2007 by $180 million ($0.59; $0.58 per share).
(3)
Dividends declared in 2011, 2010, 2009 and 2008 include four quarterly dividends of $0.55 per share. Dividends declared in 2007 include three quarterly payments of $0.50 per share in 2007 and one quarterly payment of $0.55 per share in 2008.
(4)
The retrospective change in accounting for pensions and OPEB costs increased Total Assets as of December 31 as follows: 2010 - $726 million, 2009 - $750 million, 2008 - $685 million and 2007 - $83 million.
(5)
The retrospective change in accounting for pensions and OPEB costs increased Total Equity as of December 31 as follows: 2010 - $439 million, 2009 - $457 million, 2008 - $433 million and 2007 - $122 million.
PRICE RANGE OF COMMON STOCK
The common stock of FirstEnergy Corp. is listed on the New York Stock Exchange under the symbol “FE” and is traded on other registered exchanges.
 2011 2010
 High Low High Low
First Quarter$40.80
 $36.11
 $47.09
 $38.31
Second Quarter$45.80
 $36.50
 $39.96
 $33.57
Third Quarter$46.51
 $38.77
 $39.06
 $34.51
Fourth Quarter$46.10
 $41.55
 $40.12
 $35.00
Yearly$46.51
 $36.11
 $47.09
 $33.57
Prices are from http://finance.yahoo.com.
SHAREHOLDER RETURN
The following graph shows the total cumulative return from a $100 investment on December 31, 2006 in FirstEnergy’s common stock compared with the total cumulative returns of EEI’s Index of Investor-Owned Electric Utility Companies and the S&P 500.
HOLDERS OF COMMON STOCK
There were 115,120 and 114,808 holders of 418,216,437 shares of FirstEnergy’s common stock as of December 31, 2011 and January 31, 2012, respectively. Information regarding retained earnings available for payment of cash dividends is given in Note 12, Capitalization of the Combined Notes to the Consolidated Financial Statements.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.


44


ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT AND SUBSIDIARIES

Forward-Looking Statements: This Form 10-K 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.
The impact of the regulatory process on the pending matters before FERC in the various states in which we do business including, but not limited to, matters related to rates.
The status of the PATH project in light of PJM's direction to suspend work on the project pending review of its planning process, its re-evaluation of the need for the project and the uncertainty of the timing and amounts of any related capital expenditures.
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.
Financial derivative reforms that could increase our liquidity needs and collateral costs.
The continued ability of FirstEnergy's regulated utilities to collect transition and other costs.
Operation and maintenance costs being higher than anticipated.
Other legislative and regulatory changes, and revised environmental requirements, including possible GHG emission, water intake and coal combustion residual regulations, the potential impacts of any laws, rules or regulations that ultimately replace CAIR, including CSAPR which was stayed by the courts on December 30, 2011, and the effects of the EPA's MATS rules.
The uncertainty of the timing and amounts of the capital expenditures that may arise in connection with litigation, including NSR litigation or potential regulatory initiatives or rulemakings (including that such expenditures could result in our decision to shut down or idle certain generating units).
The uncertainty associated with the company's plan to retire its older unscrubbed regulated and competitive fossil units, including the impact on vendor commitments and PJM's review of the company's plans.
Adverse regulatory or legal decisions and outcomes with respect to our nuclear operations (including, but not limited to the revocation or non-renewal of necessary licenses, approvals or operating permits by the NRC including as a result of the incident at Japan's Fukushima Daiichi Nuclear Plant).
Issues that could result from our continuing investigation and analysis of the indications of cracking in the plant shield building at Davis-Besse.
Adverse legal decisions and outcomes related to Met-Ed's and Penelec's ability to recover certain transmission costs through their transmission service charge riders.
The continuing availability of generating units and changes in their ability to operate at or near full capacity.
Replacement power costs being higher than anticipated or inadequately hedged.
The ability to comply with applicable state and federal reliability standards and energy efficiency mandates.
Changes in customers' demand for power, including but not limited to, changes resulting from the implementation of state and federal energy efficiency mandates.
The ability to accomplish or realize anticipated benefits from strategic goals.
FirstEnergy's ability to improve electric commodity margins and the impact of, among other factors, the increased cost of coal and coal transportation on such margins.
The ability to experience growth in the distribution business.
The changing market conditions that could affect the value of assets held in FirstEnergy's NDTs, pension trusts and other trust funds, and cause FirstEnergy and its subsidiaries to make additional contributions sooner, or in amounts that are larger than currently anticipated.
The impact of changes to material accounting policies.
The ability to access the public securities and other capital and credit markets in accordance with FirstEnergy's financing plan, the cost of such capital and overall condition of the capital and credit markets affecting FirstEnergy and its subsidiaries.
Changes in general economic conditions affecting FirstEnergy and its subsidiaries.
Interest rates and any actions taken by credit rating agencies that could negatively affect FirstEnergy's and its subsidiaries' access to financing or their costs of financings and increase requirements to post additional collateral to support outstanding commodity positions, LOCs and other financial guarantees.
The continuing uncertainty of the national and regional economy and its impact on major industrial and commercial customers of FirstEnergy and its subsidiaries.
Issues concerning the soundness of financial institutions and counterparties with which FirstEnergy and its subsidiaries do business.
Issues arising from the completed merger of FirstEnergy and AE and the ongoing coordination of their combined operations


45


including FirstEnergy's ability to maintain relationships with customers, employees or suppliers, as well as the ability to continue to successfully integrate the businesses and realize cost savings and any other synergies .
The risks and other factors discussed from time to time in FirstEnergy's and its applicable subsidiaries' SEC filings, and other similar factors.

Dividends declared from time to time on FE's common stock during any annual period may in the aggregate vary from the indicated amount due to circumstances considered by FE's Board of Directors at the time of the actual declarations. A security rating is not a recommendation to buy or hold securities and is subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.
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 FirstEnergy's 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. The registrants expressly disclaim any current intention to update, except as required by law, any forward-looking statements contained herein as a result of new information, future events or otherwise.
See Item 1A. Risk Factors for additional information regarding risks that may impact our business, financial condition and results of operations.


46


FIRSTENERGY CORP.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
Earnings available to FirstEnergy Corp. in 2011 were $885 million, or $2.22 per basic share of common stock ($2.21 diluted), compared with $742 million, or $2.44 per basic share of common stock ($2.42 diluted), in 2010 and $872 million, or $2.87 per basic share ($2.85 diluted), in 2009.
Change in Earnings Per Basic Share From Prior Year 2011 2010
     
Earnings Per Basic Share — Prior Year $2.44
 $2.87
Segment operating results(1)-
    
Regulated Distribution 0.05
 0.04
Competitive Energy Services (0.15) 0.10
Regulated Independent Transmission (0.06) 0.12
Non-core asset sales/impairments 0.67
 (0.37)
Generating plant impairments 0.08
 (0.78)
Trust securities impairments 0.02
 0.03
Litigation resolution (0.07) 0.01
Regulatory charges 0.03
 0.45
Mark-to-market adjustments-    
Pension and OPEB actuarial assumptions (0.47) 0.30
All other 0.02
 0.35
Organizational restructuring - 2009 —
 0.14
Debt redemption premiums (0.01) 0.32
Merger-related costs (0.29) (0.16)
Merger Accounting - commodity contracts (0.26) —
Net merger accretion(1)(2)(3)
 0.54
 —
Income tax resolution / retiree drug subsidy (0.03) (0.57)
Settlement of uncertain tax positions (0.05) (0.11)
Depreciation (0.09) (0.02)
Interest expense, net of amounts capitalized (0.14) 0.04
Investment income (0.03) (0.19)
Change in effective tax rate 0.04
 (0.17)
Other (0.02) 0.04
Earnings Per Basic Share $2.22
 $2.44
(1)Excludes amounts that are shown separately
(2)Includes dilutive effect of shares issued in connection with the Allegheny merger
(3)Includes 10 months of Allegheny results in 2011

Merger
On February 25, 2011, the merger between FirstEnergy and AE closed. Pursuant to the terms of the Agreement and Plan of Merger between FirstEnergy, Merger Sub and AE, Merger Sub merged with and into AE with AE continuing as the surviving corporation and a wholly owned subsidiary of FirstEnergy. As part of the merger, AE shareholders received 0.667 of a share of FirstEnergy common stock for each AE share outstanding as of the merger completion date and all outstanding AE equity-based employee compensation awards were converted into FirstEnergy equity-based awards on the same basis.
In connection with the merger, FirstEnergy recorded merger transaction costs of approximately $91 million ($73 million net of tax and $65 million ($47 million net of tax) during 2011 and 2010, respectively. These costs are included in “Other operating expenses” in the Consolidated Statements of Income. In addition, during 2011, $93 million of pre-tax merger integration costs and $36 million of pre-tax charges from merger settlements approved by regulatory agencies were recognized. Charges resulting from merger settlements are not expected to be material in future periods.
FirstEnergy exceeded its 2011 merger benefits target. During 2011, FirstEnergy completed savings initiatives that allowed the


47


company to capture pre-tax annualized merger benefits of approximately $267 million compared to the annual target of $210 million.

Operational Matters

PJM RTO Integration

On June 1, 2011, ATSI successfully integrated into PJM. With this transition, all of FirstEnergy's generation, transmission and distribution facilities are now in PJM.

Transmission Expansion

On May 19, 2011, TrAIL's 500-kV transmission line, spanning more than 150 miles from southwestern Pennsylvania through West Virginia to northern Virginia, was completed and energized.

Nuclear Generation

On April 11, 2011, Beaver Valley Power Station Unit 2 returned to service following a March 7, 2011 shutdown for refueling and maintenance. During the outage, 60 of the 157 fuel assemblies were exchanged, safety inspections were conducted, and numerous maintenance and improvement projects were completed that we believe will result in continued safe and reliable operations.

On June 7, 2011, the Perry Nuclear Power Plant returned to service following a scheduled shutdown for refueling and maintenance which began on April 18, 2011. During the outage, 248 of the 748 fuel assemblies were replaced and safety inspections were successfully conducted. Additionally, numerous preventative maintenance activities and improvement projects were completed that we believe will result in continued safe and reliable operations, including replacement of several control rod blades, rewind of the generator, and routine work on more than 150 valves, pumps and motors.

On October 2, 2011, FENOC completed the controlled shutdown of the Perry Plant due to the loss of a startup transformer. Subsequently, a spare replacement transformer from Davis-Besse Nuclear Power Station was transported to the Perry Plant for modification and installation. The new transformer was installed in 2011.

During 2011, FENOC broke ground for new Emergency Operations Facilities at all three of its nuclear sites. Each of the 12,000 square-foot facilities will house activities related to maintaining public health and safety during the unlikely event of an emergency at the plant and allow for improved coordination between the plant, state and local emergency management agencies.

On October 1, 2011, the Davis-Besse Nuclear Power Station began a scheduled outage for replacement of its reactor vessel head and other scheduled maintenance. On October 10, 2011, following opening of the building for installation of the new reactor head, a sub-surface hairline crack was identified in one of the exterior architectural elements on the shield building. These elements serve as architectural features and do not have structural significance. During investigation of the crack at the shield building opening, concrete samples and electronic testing found similar sub-surface hairline cracks in most of the building's architectural elements. FENOC's investigation also identified other indications of cracking. Included among them were sub-surface hairline cracks in the upper portion of the shield building (above 780 feet of elevation) and in the vicinity of the main steam line penetrations. A team of industry-recognized structural concrete experts and Davis-Besse engineers have determined these conditions do not affect the facility's structural integrity or safety. On February 27, 2012, FENOC sent a root cause evaluation report to the NRC. On December 6, 2011, the Davis-Besse Nuclear Power Station returned to service. The new reactor vessel head features control rod nozzles made of an enhanced material and further promotes safe and reliable operation of the plant.

Coal and Gas Fired Generation

On July 28, 2011, FirstEnergy completed the sale of the Fremont Energy Center to American Municipal Power, Inc. for $510 million based on 685 MW of output. The purchase price can be incrementally increased, not to exceed an additional $16 million, to reflect additional transmission export capacity up to 707 MW.

On October 18, 2011, FirstEnergy sold its Richland (432 MW) and Stryker (18 MW) Peaking Facilities for approximately $80 million. The proceeds from the sale of these non-core assets reduced FirstEnergy's net debt position.

On January 26, 2012, FirstEnergy announced that its unregulated generation subsidiaries will retire six older coal-fired plants located in Ohio, Pennsylvania and Maryland. On February 8, 2012, FirstEnergy announced that MP will retire three older coal-fired plants located in West Virginia. All of these generating plants will be closed by September 1, 2012. The decision to close the plants is the result of a comprehensive review of FirstEnergy's coal-fired generating facilities in light of the MATS rules that were recently finalized and other environmental regulations. These closures are subject to review for reliability impacts by PJM. In addition, MP will make a filing with the WVPSC to provide them with information regarding the retirement of its plants. As a result of this decision, impairment charges associated with these assets were recognized by FirstEnergy, aggregating approximately $334 million ($207 million after-tax) in the fourth quarter of 2011, including approximately $243 million ($152 million after-tax) which is applicable to FES. See Note 11, Impairment of Long-lived Assets, for further information on the retirement of these plants.



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The total capacity of the competitive plants that will be retired is approximately 2,700 MW and the total capacity of the three regulated plants that will be retired is approximately 660 MW. Recently, these plants served mostly as peaking or intermediate facilities, generating, on average, approximately 10 percent of the electricity produced by FirstEnergy's generation subsidiaries over the past three years.

On February 24, 2012, PJM notified FirstEnergy of its preliminary analysis of the reliability impacts that may result from closure of the older competitive coal-fired generating units. PJM's preliminary analysis indicated that there would be significant reliability concerns that will need to be addressed. FirstEnergy intends to continue to actively engage in discussions with PJM regarding this notification, including the possible continued operation of certain plants.

Signal Peak

On October 18, 2011, FirstEnergy announced that Gunvor Group, Ltd. purchased a one-third interest in Global Holding, a joint venture that owns the Signal Peak coal mine in Montana and the related Global Rail coal transportation operations. The sale strengthened FirstEnergy's balance sheet in the following ways:

Proceeds of $257.5 million reduced FirstEnergy's net debt position;
De-consolidation of Signal Peak resulted in the reduction of indebtedness by $360 million and an increase to equity of $50 million on FirstEnergy's Consolidated Balance Sheet; and
The gain on sale and revaluation of FirstEnergy's remaining ownership stake increased equity by an additional $370 million.

Following the sale, FirstEnergy, through its wholly owned subsidiary, FEV, has a one-third interest in Global Holding. FGCO has a long-term coal supply agreement with Signal Peak for up to 10 million tons per year. FGCO has re-evaluated its coal usage under that agreement and has determined to resell its coal purchased from Signal Peak to an affiliate of Global Holding; provided, however, that such affiliate may require FGCO to repurchase up to 2 million tons annually from the existing underground mines, and, if Signal Peak develops surface mines, it could require FGCO to purchase an additional 2 million tons per year. FirstEnergy remains a 100% guarantor on Signal Peak's and Global Rail's $350 million senior secured credit facility. See Guarantees and Other Assurances below.

FirstEnergy Utilities Respond to Unprecedented Storms

In late August 2011, FirstEnergy experienced unprecedented damage in its service territory as a result of Hurricane Irene. Approximately 1.1 million customers were affected by outages in areas served by JCP&L, Met-Ed, Penelec and PE. Approximately 5,000 FirstEnergy employees and 2,800 contractors, including utility line workers from other utilities, assisted with the restoration work. The cost of the storm totaled approximately $89 million, of which $4 million reduced pre-tax income in 2011 and $85 million was capitalized or deferred for future recovery from customers.

On October 29, 2011, FirstEnergy was affected by a snowstorm that paralyzed much of the East Coast, including our eastern service areas. Approximately 820,000 customers of JCP&L, Met-Ed, PE, MP, Penelec and WP were affected by the storm that brought down more than 800 poles and approximately 10,000 spans of wire. More than 9,600 employees, contractors and other utilities' crews helped in the restoration. The pre-tax total cost of the storm was approximately $125 million, of which $6 million reduced pre-tax income in 2011 and $119 million was capitalized or deferred for future recovery from customers.

Financial Matters
During 2011, FirstEnergy redeemed or repurchased approximately $520.4 million principal amount of PCRBs, as summarized in the following table. Approximately $28.5 million of FGCO FMBs and $98.9 million of NGC FMBs associated with the PCRBs were returned for cancellation by the associated LOC providers.
SubsidiariesAmount 
 (In millions) 
AE Supply$53.0
(1) 
FGCO$198.2
(2) 
NGC$213.5
(2) 
MP$70.2
(1) 
(1)
Includes $14.4 million of PCRBs redeemed for which MP and AE Supply are co-obligors.
(2)
Subject to market conditions, these PCRBs are being held for future remarketing.

On May 4, 2011, AE terminated its $250 million credit facility due to other available funding sources following completion of the merger with FirstEnergy.

On June 17, 2011, FirstEnergy and certain of its subsidiaries entered into two 5-year revolving credit facilities with a total borrowing capacity of $4.5 billion. These facilities consist of a $2 billion revolving credit facility for FirstEnergy and its regulated utility subsidiaries


49


and a $2.5 billion revolving credit facility for FES and AE Supply. Prior separate facilities ($2.75 billion at FirstEnergy, $1 billion at AE Supply, $110 million at MP, $150 million at PE and $200 million at WP) were terminated.

During the third quarter of 2011, FirstEnergy received approximately $130 million from assigning a substantially below-market, long-term fossil fuel contract to a third party. As a result, FirstEnergy entered into a new long-term contract with another supplier for replacement fuel based on current market prices. The new contract runs for nine years, which is the remaining term of the assigned contract. The transaction reduced fuel costs during the quarter by approximately $123 million.

TrAIL's primary investment, the Trans-Allegheny Interstate Line (a 500-kV transmission project that extends from Southwestern Pennsylvania through West Virginia to Northern Virginia), was completed in May 2011.

On January 26, 2012, FirstEnergy announced a change to its method for accounting for pensions and OPEB effective in 2011 (see Note 1, Organization, Basis of Presentation and Significant Accounting Policies of the Combined Notes to the Consolidated Financial Statements). We also disclosed that we made a $600 million voluntary contribution to our pension plan earlier that month.

Regulatory Matters

Met-Ed and Penelec Transition to Competitive Markets

The Pennsylvania Companies began the move to competitive markets with the expiration of the rate caps on Met-Ed's and Penelec's retail generation rates on December 31, 2010. Beginning in 2011, Met-Ed and Penelec obtained their power supply from the competitive wholesale market and fully recover their generation costs through retail rates. The Ohio Companies, Penn, WP and JCP&L previously transitioned to competitive generation markets.

Marginal transmission loss recovery

On March 3, 2010, the PPUC issued an order denying Met-Ed and Penelec the ability to recover marginal transmission losses through the transmission service charge riders in their respective tariffs which applies to the periods including June 1, 2008 through December 31, 2010. Subsequently, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania (Commonwealth Court) appealing the PPUC's order. On June 14, 2011, the Commonwealth Court affirmed the PPUC's decision that marginal transmission losses are not recoverable as transmission costs. On July 13, 2011, Met-Ed and Penelec filed a federal complaint with the United States District Court for the Eastern District of Pennsylvania and on the following day, filed a Petition for Allowance of Appeal to the Pennsylvania Supreme Court. Met-Ed and Penelec believe the Commonwealth Court's decision contradicts federal law and is inconsistent with prior PPUC and court decisions and therefore expect to fully recover the related regulatory assets ($189 million for Met-Ed and $65 million for Penelec). In January 2011 and continuing for 29 months, pursuant to a related PPUC order, Met-Ed and Penelec began crediting customers for the amounts at issue pending the outcome of court appeals.

Ohio Energy Efficiency and Peak Demand Reduction Portfolio Plan

On March 23, 2011, the PUCO approved the three-year Energy Efficiency and Demand Reduction portfolio plan for the Ohio Companies. The Ohio Companies' plan was developed to comply with the Energy Efficiency mandate in Ohio's SB 221, passed in 2008. This law requires that utilities in Ohio reduce energy usage by 22.2 percent by 2025 and peak demand by 7.75 percent by 2018, develop a portfolio plan, and meet annual benchmarks to measure progress.

NYSEG Ruling

On July 11, 2011, FirstEnergy was found to be a potentially responsible party under CERCLA indirectly liable for a portion of past and future clean-up costs at certain legacy MGP sites in New York. As a result, FirstEnergy recognized additional expense of $29 million during the second quarter of 2011.

West Virginia Fuel, Purchased Power Cost Decision

On December 30, 2011, MP and PE announced that the WVPSC issued an order regarding the companies' adjustment of fuel and purchased power costs. The WVPSC's order approved a settlement agreement between the companies, the Consumer Advocate Division, the Staff of the WVPSC and the West Virginia Energy Users Group. In the approved settlement, parties have agreed that the companies will recover an additional $19.6 million in 2012, an approximate 1.7 percent increase, primarily reflecting rising coal prices over the past two years, with certain additional amounts to be recovered over time with a carrying charge.
FIRSTENERGY’S BUSINESS
With the completion of the AE merger in the first quarter of 2011, FirstEnergy reorganized its management structure, which resulted in changes to its operating segments to be consistent with the manner in which management views the business. The new structure supports the combined company's primary operations - distribution, transmission, generation and the marketing and sale of its products. The external segment reporting is consistent with the internal financial reporting used by FirstEnergy's chief executive


50


officer (its chief operating decision maker) to regularly assess the performance of the business and allocate resources. FirstEnergy now has three reportable operating segments - Regulated Distribution, Regulated Independent Transmission and Competitive Energy Services.
Prior to the change in composition of business segments, FirstEnergy's business was comprised of two reportable operating segments. The Energy Delivery Services segment was comprised of FirstEnergy's then eight existing utility operating companies that transmit and distribute electricity to customers and purchase power to serve their POLR and default service requirements. The Competitive Energy Services segment was comprised of FES, which supplies electric power to end-use customers through retail and wholesale arrangements. The “Other/Corporate” amounts consisted of corporate items and other businesses that were below the quantifiable threshold for separate disclosure. Disclosures for FirstEnergy's operating segments for 2010 have been reclassified to conform to the revised presentation.
The changes in FirstEnergy's reportable segments during 2011 consisted primarily of the following:
Energy Delivery Services was renamed Regulated Distribution and the operations of MP, PE and WP, which were acquired as part of the merger with AE, and certain regulatory asset recovery mechanisms formerly included in the “Other/Corporate” segment, were placed into this segment.
A new Regulated Independent Transmission segment was created consisting of ATSI, and the operations of TrAIL and FirstEnergy's interest in PATH; TrAIL and PATH were acquired as part of the merger with AE. The transmission assets and operations of JCP&L, Met-Ed, Penelec, MP, PE and WP remained within the Regulated Distribution segment.
AE Supply, an operator of generation facilities that was acquired as part of the merger with AE, was placed into the Competitive Energy Services segment with FES.

Regulated Distribution distributes electricity through our ten utility distribution companies, serving approximately 6 million customers within 67,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also includes the transmission operations of JCP&L, Met-Ed, Penelec, WP, MP and PE and the regulated electric generation facilities in West Virginia and New Jersey which MP and JCP&L, respectively, own or contractually control. Its results reflect the commodity costs of securing electric generation and the deferral and amortization of certain fuel costs.
The service areas of our regulated distribution utilities are summarized below:
CompanyArea ServedCustomers Served
OECentral and Northeastern Ohio1,032,000
PennWestern Pennsylvania161,000
CEINortheastern Ohio747,000
TENorthwestern Ohio309,000
JCP&LNorthern, Western and East Central New Jersey1,099,000
Met-EdEastern Pennsylvania553,000
PenelecWestern Pennsylvania590,000
WPSouthwest, South Central and Northern Pennsylvania718,000
MPNorthern, Central and Southeastern West Virginia387,000
PEWestern Maryland and Eastern West Virginia390,000
5,986,000

Regulated Independent Transmission transmits electricity through transmission lines and its revenues are primarily derived from a formulaic rate that recovers costs and a return on investment for capital expenditures in connection with TrAIL, PATH and other projects, revenues from providing transmission services to electric energy providers and power marketers, and revenues from operating a portion of the FirstEnergy transmission system. Its results reflect the net transmission expenses related to the delivery of the respective generation loads.

Competitive Energy Services supplies, through FES and AE Supply, electric power to end-use customers through retail and wholesale arrangements, including competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland and the provision of partial POLR and default service for some utilities in Ohio, Pennsylvania and Maryland, including but not limited to the Utilities. This segment controls approximately 17,000 MWs of capacity (excluding approximately 2,700 MWs from unregulated plants expected to be closed by September 1, 2012) (see Note 11, Impairment of Long-Lived Assets of the Combined Notes to the Consolidated Financial Statements) and also purchases electricity to meet sales obligations. The segment's net income is primarily derived from electric generation sales less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO (prior to June 1, 2011)


51


to deliver energy to the segment's customers.
Other/Corporate contains corporate items and other businesses that are below the quantifiable threshold for separate disclosure as a reportable segment. (See Note 19, Segment Information of the Combined Notes to the Consolidated Financial Statements for further information on FirstEnergy's reportable operating segments.)
STRATEGY AND OUTLOOK

FirstEnergy's vision is to be a leading regional energy provider, recognized for operational excellence, outstanding customer service and our commitment to safety; the choice for long-term growth, investment value and financial strength; and a company driven by the leadership, skills, diversity and character of our employees.

FirstEnergy has grown over the last 15 years through several strategic mergers and asset transactions. Our most recent merger with Allegheny was completed in February 2011, significantly increasing our customer base and generating capacity and accelerating our movement further into eastern competitive markets. Also during 2011, we completed the transition to competitive markets in Pennsylvania and moved our ATSI assets into PJM, so that we now operate within a single regional transmission system.

FirstEnergy is uniquely positioned as the nation's largest contiguous electric system, with complementary assets across our generation, transmission and distribution delivery operations. These assets are in a prime location of PJM's competitive markets.

Our substantial regulated operations include 10 distribution utilities serving a balanced base of nearly 6 million customers across 5 states. We are also one of the largest owners of transmission assets in PJM with nearly 20,000 miles of high-voltage lines, including two independent transmission companies with significant assets. Combined, our utilities and transmission operations provide financial stability with strong cash flow and dividend support to FirstEnergy.

Our market-focused business model integrates more than 17,000 MWs of competitive generation, excluding approximately 2,700 MWs from unregulated plants expected to be closed by September 1, 2012, and are subject to review by PJM for reliability impacts(see Note 16, Commitment, Guarantees and Contingencies, regarding PJM's review of the our plans), with a multi-channel retail sales platform, providing a higher value for every MWH we generate. We primarily target customers in competitive markets close to our generation assets.

We believe we are well-positioned for upcoming environmental changes due to the considerable investments we have made in recent years to diversify our generation fleet and improve its environmental performance. As a result of the MATS rules recently finalized by the EPA, and other previously announced environmental regulations, FirstEnergy announced in early 2012 its intent to retire nine older coal-fired power plants, totaling 3,349 MW, located in Ohio, Pennsylvania, Maryland and West Virginia by September 1, 2012. When the retired fossil plants are removed from our fleet, nearly 100% percent of our generation output will be from either low or non-emitting facilities, including nuclear, hydro, natural gas and scrubbed coal units. This further positions our fleet to deliver superior value in the future.

We continue to face challenges related to macro-economic factors. These include slow economic recovery across portions of our service territory, which affect our distribution deliveries volumes to residential, commercial and industrial customers, and depressed natural gas and wholesale electricity prices, which affect revenues from our competitive retail business and generation fleet. However, we believe we are one of the better positioned companies in our industry to benefit from eventual increases in energy and capacity prices as economic conditions improve.

Financial Outlook

We intend to manage our operating and capital costs in order to achieve our financial goals and commitment to shareholders.

Our liquidity position remains strong, with approximately $49 million of short-term cash investments and over $4.3 billion of available liquidity as of January 31, 2012.

Positive earnings drivers for 2012 are expected to include:

▪A full year contribution from the Allegheny merger;

▪Higher competitive retail revenues as a result of continued growth in the business;

▪Lower fuel and operation and maintenance expenses due to the retirement of certain coal-fired plants in 2012 and from a continued focus on controlling our costs; and

▪Reduced interest expense as a result of debt redemptions during 2011.

Negative earnings drivers for 2012 are expected to include:

▪Lower margins for our competitive energy service business from depressed market prices of power and lower capacity


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prices resulting from the PJM RPM auction beginning June 1, 2012;

▪Higher gross receipts taxes associated with increased competitive retail sales in Pennsylvania; and

▪Increased depreciation expenses from capital projects that were placed in service during 2011.

On January 5, 2012, we made a $600 million voluntary contribution to our pension plan bringing its funding level to 90% on an accumulated benefit obligation basis.

Capital Expenditures Outlook

Our capital expenditures in 2012 are estimated to be $2.1 billion (excluding nuclear fuel), a decrease of approximately $393 million from 2011. In addition to internal sources to fund capital requirements for 2012 and beyond, FirstEnergy expects to rely on external sources of funds.

Capital expenditures for our Regulated Distribution segment are forecast to decrease by $63 million in 2012 from $1.1 billion in 2011. The expected decrease primarily reflects the absence of storm restoration costs related to Hurricane Irene and the October 2011 snowstorm. For our Regulated Independent Transmission segment, capital expenditures are expected to decrease to $105 million in 2012 from $190 million in 2011. The decrease reflects the completion of TrAIL's 500-kV transmission line in 2011.

Expenditures for Ohio and Pennsylvania energy efficiency and advanced metering initiatives are expected to be primarily recovered from distribution customers and federal stimulus funding. Other capital investments in our transmission and distribution infrastructure are planned to satisfy transmission capacity and reliability requirements, connect new load delivery and wholesale generation points, and achieve cost-effective improvements in the reliability of our service.

For our Competitive Energy Services segment, capital expenditures are expected to increase by $32 million to $803 million in 2012. The main drivers of the increase include steam generator replacement projects at Davis-Besse and Beaver Valley Unit 2 and turbine rotor replacement projects at Perry and Beaver Valley Unit 2. Other planned generation investments provide for maintenance of critical generation assets, delivering operational improvements to enhance reliability, supporting environmental compliance, and advancing our generation to market strategy.

For 2013, we anticipate baseline capital expenditures of approximately $2.0 billion, which exclude any potential additional strategic opportunities, future mandated spending, energy efficiency or environmental spending relating to MATS. Planned capital initiatives are intended to promote reliability, improve operations, and support current environmental and energy efficiency directives.

Environmental Outlook

We continually strive to enhance environmental protection and remain good stewards of our natural resources. We devote significant resources to environmental compliance efforts, and our employees share a commitment to, and accountability for, environmental performance. Our corporate focus on continuous improvement is integral to our environmental programs.

We have spent more than $10 billion on environmental protection efforts since the initial passage of the Clean Air and Water Acts in the 1970s, and these investments demonstrate our continuing commitment to the environment. Recent investments of $3.0 billion at our Hatfield, Fort Martin and Sammis Plants, further reduced emissions of SO2 by over 95%, and NOx by at least 64% at these facilities. Since 1990, we have reduced emissions of NOx by more than 76%, SO2 by more than 86%, and mercury by approximately 56%.

We have taken aggressive steps over the past two decades that have increased our generating capacity without adding to overall CO2 emissions. For example, since 1990, we have reconfigured our fleet by retiring 1,312 MWs and committing to retire in the near future 3,349 MWs of older, coal-based generation and adding more than 1,800 MWs of non-emitting capacity. Through these and other actions, we have increased our generating capacity by nearly 15% over the same period while avoiding over 370 million metric tons of CO2 emissions.

We have taken a leadership role in pursuing new ventures to test and develop new technologies that may achieve additional reductions in CO2 emissions. These include:

Sales of over 1 million MWH per year of wind generation.

CO2 sequestration testing to gain a better understanding of the potential for geological storage of CO2.

Supporting afforestation - growing forests on non-forested land - and other efforts designed to remove CO2 from the environment.

Reducing emissions of SF6 (sulfur hexafluoride) by nearly 15 metric tons, resulting in an equivalent reduction of nearly 315,000 metric tons of CO2, through the EPA's SF6 Emissions Reduction Partnership for Electric Power Systems.



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Supporting research to develop and evaluate cost effective sorbent materials for CO2 capture including work by EPRI and The University of Akron.

We remain actively engaged in the federal and state debate over future environmental requirements and legislation. We actively work with policy makers and regulators to develop fair and reasonable requirements, with the goal of reducing emissions while minimizing the economic impact on our customers. Due to the significant uncertainty as to the final form or timing of a significant number of regulations and legislation at both the federal and state levels, we are unable to determine the potential impact and risks associated with all future environmental requirements. The CSAPR was stayed at the end of 2011 and the federal appeals court reviewing CSAPR has scheduled an April 13, 2012 hearing. The new MATS were finalized at the end of 2011, which resulted in our decision to retire nine older coal-fired generation plants by September 1, 2012. Our current estimate is that it may cost approximately $1.3 - $1.7 billion to bring our remaining units into compliance.

We also have a long history of supporting research in distributed energy resources. Distributed energy resources include fuel cells, solar and wind systems or energy storage technologies located close to the customer or direct control of customer loads to provide alternatives or enhancements to the traditional electric power system. We are testing the world's largest utility-scale fuel cell system to determine its feasibility for augmenting generating capacity during summer peak-use periods. Through a partnership with EPRI, the Cuyahoga Valley National Park, the Department of Defense and Case Western Reserve University, two solid-oxide fuel cells were installed as part of a test program to explore the technology and the environmental benefits of distributed generation.

We are also evaluating the impact of distributed energy storage on the distribution system through analysis and field demonstrations of advanced battery technologies. FirstEnergy's EasyGreen® load-management program utilizes two-way communication capability with customers' non-critical equipment, such as air conditioners in New Jersey and Pennsylvania, to help manage peak loading on the electric distribution system. We have also made an online interactive energy efficiency tool, Home Energy Analyzer, available to our customers to help achieve electricity use reduction goals.
RISKS AND CHALLENGES
In executing our strategy, we face a number of industry and enterprise risks and challenges. See ITEM 1A. RISK FACTORS for a discussion of the risks and challenges faced by FirstEnergy and the Registrants.
RESULTS OF OPERATIONS
The financial results discussed below include revenues and expenses from transactions among FirstEnergy’s business segments. A reconciliation of segment financial results is provided in Note 19, Segment Information of the Combined Notes to the Consolidated Financial Statements. As described in Note 1, Organization, Basis of Presentation and Significant Accounting Policies, FirstEnergy elected to change its method of recognizing actuarial gains and losses for its defined benefit pension and OPEB plans and applied this change retrospectively to all periods presented. Earnings available to FirstEnergy by major business segment were as follows:
       Increase (Decrease)
 2011 2010 2009 2011 vs 2010 2010 vs 2009
 (In millions, except per share data)
Earnings By Business Segment:         
Regulated Distribution$570
 $553
 $335
 $17
 $218
Competitive Energy Services377
 210
 446
 167
 (236)
Regulated Independent Transmission112
 54
 39
 58
 15
Other and reconciling adjustments(1)
(174) (75) 52
 (99) (127)
Earnings available to FirstEnergy Corp.$885
 $742
 $872
 $143
 $(130)
          
Earnings Per Basic Share$2.22
 $2.44
 $2.87
 $(0.22) $(0.43)
          
Earnings Per Diluted Share$2.21
 $2.42
 $2.85
 $(0.21) $(0.43)
(1)
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 — 2011 Compared with 2010
Financial results for FirstEnergy’s major business segments in 2011 and 2010 were as follows:


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2011 Financial Results Regulated Distribution Competitive Energy Services Regulated Independent Transmission Other and Reconciling Adjustments FirstEnergy Consolidated
  (In millions)
Revenues:          
External          
Electric $9,544
 $5,573
 $—
 $—
 $15,117
Other 460
 363
 391
 (140) 1,074
Internal —
 1,237
 —
 (1,170) 67
Total Revenues 10,004
 7,173
 391
 (1,310) 16,258
           
Operating Expenses:          
Fuel 268
 2,049
 —
 —
 2,317
Purchased power 4,672
 1,491
 —
 (1,177) 4,986
Other operating expenses 1,662
 2,256
 68
 (77) 3,909
Pensions and OPEB mark-to-market adjustment 290
 215
 2
 —
 507
Provision for depreciation 620
 415
 60
 26
 1,121
Amortization of regulatory assets, net 323
 —
 6
 —
 329
General taxes 724
 200
 33
 21
 978
Impairment of long-lived assets 87
 315
 —
 11
 413
Total Operating Expenses 8,646
 6,941
 169
 (1,196) 14,560
           
Operating Income 1,358
 232
 222
 (114) 1,698
           
Other Income (Expense):          
Gain on partial sale of Signal Peak —
 569
 —
 —
 569
Investment income 110
 56
 —
 (52) 114
Interest expense (573) (298) (46) (91) (1,008)
Capitalized interest 10
 40
 2
 18
 70
Total Other Income (Expense) (453) 367
 (44) (125) (255)
           
Income Before Income Taxes 905
 599
 178
 (239) 1,443
Income taxes 335
 222
 66
 (49) 574
Net Income 570
 377
 112
 (190) 869
Loss attributable to noncontrolling interest —
 —
 —
 (16) (16)
Earnings available to FirstEnergy Corp. $570
 $377
 $112
 $(174) $885


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2010 Financial Results Regulated Distribution Competitive Energy Services Regulated Independent Transmission Other and Reconciling Adjustments FirstEnergy Consolidated
  (In millions)
Revenues:          
External          
Electric $9,271
 $3,252
 $—
 $—
 $12,523
Other 300
 323
 242
 (123) 742
Internal 139
 2,301
 —
 (2,366) 74
Total Revenues 9,710
 5,876
 242
 (2,489) 13,339
           
Operating Expenses:          
Fuel —
 1,432
 —
 —
 1,432
Purchased power 5,273
 1,724
 —
 (2,373) 4,624
Other operating expenses 1,320
 1,393
 61
 (78) 2,696
Pensions and OPEB mark-to-market adjustment 82
 107
 (2) 3
 190
Provision for depreciation 433
 284
 37
 14
 768
Amortization of regulatory assets, net 712
 —
 10
 —
 722
General taxes 605
 124
 30
 17
 776
Impairment of long-lived assets —
 388
 —
 —
 388
Total Operating Expenses 8,425
 5,452
 136
 (2,417) 11,596
           
Operating Income 1,285
 424
 106
 (72) 1,743
           
Other Income (Expense):          
Investment income 102
 51
 —
 (36) 117
Interest expense (500) (232) (22) (91) (845)
Capitalized interest 4
 95
 2
 64
 165
Total Other Expense (394) (86) (20) (63) (563)
           
Income Before Income Taxes 891
 338
 86
 (135) 1,180
Income taxes 338
 128
 32
 (36) 462
Net Income 553
 210
 54
 (99) 718
Loss attributable to noncontrolling interest —
 —
 —
 (24) (24)
Earnings available to FirstEnergy Corp. $553
 $210
 $54
 $(75) $742



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Changes Between 2011 and 2010 Financial Results
Increase (Decrease)
 Regulated Distribution Competitive Energy Services Regulated Independent Transmission Other and Reconciling Adjustments FirstEnergy Consolidated
  (In millions)
Revenues:          
External          
Electric $273
 $2,321
 $—
 $—
 $2,594
Other 160
 40
 149
 (17) 332
Internal (139) (1,064) —
 1,196
 (7)
Total Revenues 294
 1,297
 149
 1,179
 2,919
           
Operating Expenses:          
Fuel 268
 617
 —
 —
 885
Purchased power (601) (233) —
 1,196
 362
Other operating expenses 342
 863
 7
 1
 1,213
Pensions and OPEB mark-to-market adjustment 208
 108
 4
 (3) 317
Provision for depreciation 187
 131
 23
 12
 353
Amortization of regulatory assets, net (389) —
 (4) —
 (393)
General taxes 119
 76
 3
 4
 202
Impairment of long-lived assets 87
 (73) —
 11
 25
Total Operating Expenses 221
 1,489
 33
 1,221
 2,964
           
Operating Income 73
 (192) 116
 (42) (45)
           
Other Income (Expense):          
Gain on partial sale of Signal Peak —
 569
 —
 —
 569
Investment income 8
 5
 —
 (16) (3)
Interest expense (73) (66) (24) —
 (163)
Capitalized interest 6
 (55) —
 (46) (95)
Total Other Income (Expense) (59) 453
 (24) (62) 308
           
Income Before Income Taxes 14
 261
 92
 (104) 263
Income taxes (3) 94
 34
 (13) 112
Net Income 17
 167
 58
 (91) 151
Loss attributable to noncontrolling interest —
 —
 —
 8
 8
Earnings available to FirstEnergy Corp. $17
 $167
 $58
 $(99) $143
Regulated Distribution — 2011 Compared with 2010
Net income increased by $17 million in 2011 compared to 2010, primarily due to earnings from the Allegheny companies and the absence of a 2010 regulatory asset impairment associated with the Ohio companies' ESP, partially offset by higher pensions and OPEB mark-to-market adjustment charges and merger-related costs. Lower generation revenues were offset with lower purchased power expenses.


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Revenues —
The increase in total revenues resulted from the following sources:
  For the year ended December 31  
Revenues by Type of Service 2011 2010 
Increase
(Decrease)
  (In millions)
Pre-merger companies:      
Distribution services $3,426
 $3,629
 $(203)
Generation:      
Retail 3,266
 4,457
 (1,191)
Wholesale 377
 702
 (325)
Total generation sales 3,643

5,159
 (1,516)
Transmission 262
 596
 (334)
Other 187
 326
 (139)
Total pre-merger companies 7,518
 9,710
 (2,192)
Allegheny companies 2,486
 —
 2,486
Total Revenues $10,004
 $9,710
 $294

The decrease in distribution service revenues for the pre-merger companies (FirstEnergy as it was organized prior to the February 2011 merger with Allegheny) primarily reflects lower transition revenues due to the completion of transition cost recovery by CEI in December 2010, an NJBPU-approved rate adjustment that became effective March 1, 2011, for all JCP&L customer classes, and the mid-year suspension of the Ohio Companies' recovery of deferred distribution costs. Partially offsetting the decreased distribution service revenues were increased rates in Met-Ed's and Penelec's transition riders and energy efficiency riders for the Pennsylvania and Ohio Companies. Distribution deliveries (excluding the Allegheny companies) increased by 0.1% in 2011 from 2010.The change in distribution deliveries by customer class is summarized in the following table:
  For the year ended December 31  
Electric Distribution MWH Deliveries 2011 2010 
Increase
(Decrease)
     
Pre-merger companies:      
Residential 39,369
 39,820
 (1.1)%
Commercial 32,610
 33,096
 (1.5)%
Industrial 35,637
 34,613
 3.0 %
Other 513
 522
 (1.7)%
Total pre-merger companies 108,129
 108,051
 0.1 %
Allegheny companies 33,449
    
Total Electric Distribution MWH Deliveries 141,578
 108,051
 31.0 %

Lower deliveries to residential and commercial customers primarily reflected decreased weather-related usage resulting from lower heating degree days (4%) and cooling degree days (7%) in 2011 compared to 2010. In the industrial sector, MWH deliveries increased to steel and electrical equipment customers by 10% and 12%, respectively, partially offset by decreased deliveries to automotive customers of 2% in 2011 compared to 2010.


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The following table summarizes the price and volume factors contributing to the $1,516 million decrease in generation revenues for the pre-merger companies in 2011 compared to 2010:
Source of Change in Generation Revenues 
Increase
(Decrease)
  (In millions)
Retail:  
Effect of decrease in sales volumes $(1,638)
Change in prices 447
  (1,191)
Wholesale:  
Effect of decrease in sales volumes (104)
Change in prices (221)
  (325)
Net Decrease in Generation Revenues $(1,516)

The decrease in retail generation sales volume was primarily due to increased customer shopping in the service territories of the pre-merger companies in 2011 compared to 2010. Total generation provided by alternative suppliers as a percentage of total MWH deliveries increased to 76% from 62% for the Ohio Companies, and to 52% from 10% in Met-Ed’s, Penelec’s and Penn's service territories. The increase in retail prices is the result of higher generation charges in Pennsylvania due to the removal of generation rate caps for Met-Ed and Penelec beginning on January 1, 2011, and the inclusion of transmission as part of the price of generation. Those impacts were partially offset by a decrease in the Ohio Companies' generation rates beginning in June 2011 with the removal of certain transmission charges in connection with the integration into PJM.
The decrease in wholesale generation revenues reflected lower RPM revenues for Met-Ed and Penelec in the PJM market.
Transmission revenues decreased $334million primarily due to the termination of Met-Ed’s and Penelec’s TSC rates effective January 1, 2011. This is partially offset by a new rider that became effective for the Ohio Companies in June 2011 that recovers network integration transmission service charges.
Other revenues decreased by $139 million primarily due to the termination of Met-Ed's and Penelec's PSA with FES as of December 31, 2010, resulting in decreased capacity revenues.
The Allegheny companies added $2,486 million to revenues in 2011, including $571 million for distribution services, $1,661million from generation sales, $212 million of transmission revenues and $42 million of other revenues.
Operating Expenses —
Total operating expenses increased by $221 million in 2011. Excluding the Allegheny companies, total operating expenses decreased $1.9 billion due to the following:

Purchased power costs were $1.7 billion lower in 2011 due primarily to a decrease in volumes required. Decreased power purchased from FES primarily reflected the increase in customer shopping described above, the termination of Met-Ed’s and Penelec’s PSA with FES at the end of 2010, and less Ohio POLR load served by FES beginning in June 2011. The increase in volumes purchased from non-affiliates in 2011 is primarily due to Met-Ed’s and Penelec’s generation procurement plan effective January 1, 2011 and more Ohio POLR load served by non-affiliates, partially offset by a decrease in RPM expenses in the PJM market.


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Source of Change in Purchased Power 
Increase
(Decrease)
  (In millions)
Pre-merger companies:  
Purchases from non-affiliates:  
Change due to decreased unit costs $(826)
Change due to increased volumes 515
  (311)
Purchases from FES:  
Change due to increased unit costs 165
Change due to decreased volumes (1,601)
  (1,436)
   
Total pre-merger companies (1,747)
Purchases by Allegheny companies 1,146
Net Decrease in Purchased Power Costs $(601)
Other operating expenses decreased $37 million, primarily due to the following:
◦Storm restoration maintenance and removal expenses increased $126 million primarily related to restoration associated with Hurricane Irene and an October 2011 East Coast snowstorm, primarily impacting the JCP&L and Met-Ed service territories. Approximately $120 million of the total costs were deferred for future recovery from customers.
◦Energy efficiency program costs, which are also recovered through rates, increased by $92 million.
◦
A provision for excess and obsolete material of $13 million was recognized in 2011 due to revised inventory practices adopted in conjunction with the Allegheny merger.
◦The absence of a $7 million favorable JCP&L labor settlement that occurred in 2010.
◦Transmission expenses decreased $285 million primarily due to reduced congestion costs for Met-Ed and Penelec in 2011.
Pensions and OPEB mark-to-market adjustment charges increased $132 million as a result of higher net actuarial losses.
Depreciation expense increased $24 million primarily due to property additions since 2010.
Net amortization of regulatory assets decreased $368 million primarily due to reduced net PJM transmission and transition cost recovery, the absence of a $35 million regulatory asset impairment recognized in 2010 associated with the filing of the Ohio Companies' ESP on March 23, 2010, and the deferral of recoverable costs from Hurricane Irene and the 2011 East Coast snowstorm, partially offset by increased energy efficiency cost recovery.
General Taxes increased $10 million due to the absence of a favorable property tax settlement recognized in 2010.
Impairments of long-lived assets totaling $87 million in 2011 resulted from the pending shutdown of three coal-fired plants in West Virginia.


60


The acquisition of the Allegheny companies resulted in the inclusion of the following operating expenses in 2011:
Operating Expenses - Allegheny In Millions
   
Purchased power $1,146
Fuel 268
Transmission 120
Amortization of regulatory assets, net (21)
Pensions and OPEB mark-to-market adjustment 76
Other operating expenses 259
General taxes 109
Depreciation expense 163
Total Operating Expenses $2,120
Other Expense —
Other expense increased $59 million in 2011 due to interest expense on debt of the Allegheny companies partially offset by higher investment income on OE's and TE's nuclear decommissioning trusts and increased capitalized interest.
Regulated Independent Transmission — 2011 Compared with 2010
Net income increased by $58 million in 2011 compared to 2010 due to earnings associated with TrAIL and PATH of $79 million, partially offset by decreased earnings for ATSI of $20 million.
Revenues —
Total revenues increased by $149 million principally due to revenues from TrAIL and PATH, which were acquired as part of the merger with Allegheny, partially offset by a decrease in ATSI revenues due to the transition from MISO to PJM and the completion of vegetation management cost recovery in May 2011.
Revenues by transmission asset owner are shown in the following table:
Revenues by Transmission Asset Owner 2011 2010 
Increase
(Decrease)
  (In millions)
ATSI $207
 $242
 $(35)
TrAIL 170
 —
 170
PATH 14
 —
 14
Total Revenues $391
 $242
 $149
Operating Expenses —
Total operating expenses increased by $33 million principally due to the addition of TrAIL and PATH in 2011.
Other Expense —
Other expense increased $24 million in 2011 due to additional interest expense associated with TrAIL.
Competitive Energy Services — 2011 Compared to 2010
Net income increased by $166 million in 2011 compared to 2010. The increase in net income was primarily due to a $569 million gain ($358 million net of tax) on the partial sale of FEV's interest in Signal Peak in 2011 and decreased impairments of long-lived assets. Partially offsetting this was a decrease in sales margins of $193 million, a $66 million increase in interest expense and a $55 million decrease in capitalized interest compared to 2010.
Revenues —
Total revenues increased $1.3 billion in 2011 compared to 2010, primarily due to an increase in direct and governmental aggregation sales and the inclusion of the Allegheny companies, partially offset by a decline in POLR and structured sales.


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The increase in reported segment revenues resulted from the following sources:
Revenues by Type of Service 2011 2010 Increase (Decrease)
  (In millions)
Direct and Governmental Aggregation $3,785
 $2,493
 $1,292
POLR and Structured Sales 944
 2,589
 (1,645)
Wholesale 457
 397
 60
Transmission 108
 77
 31
RECs 67
 74
 (7)
Sale of OVEC participation interest —
 85
 (85)
Other 173
 161
 12
Allegheny Companies 1,639
 —
 1,639
Total Revenues $7,173
 $5,876
 $1,297
       
Allegheny Companies      
Direct and Government Aggregation $84
   

POLR and Structured Sales 561
   

Wholesale 912
   

Transmission 88
   

Other (6)   

Total Revenues $1,639
 

 

MWH Sales by Type of Service 2011 2010 Increase (Decrease)
  (In thousands)
Direct 46,187
 28,499
 17,688
Government Aggregation 17,722
 12,796
 4,926
POLR and Structured Sales 15,340
 50,358
 (35,018)
Wholesale 2,916
 5,391
 (2,475)
Allegheny Companies 26,609
 —
 26,609
Total Sales 108,774
 97,044
 11,730
       
Allegheny Companies      
Direct 1,390
   

POLR 7,974
   

Structured Sales 1,492
   

Wholesale 15,753
   

Total Sales 26,609
 




The increase in direct and governmental aggregation revenues of $1.3 billion resulted from the acquisition of new residential, commercial and industrial customers, as well as new governmental aggregation contracts with communities in Ohio and Illinois that provide generation to approximately 1.8 million residential and small commercial customers at the end of 2011 compared to approximately 1.5 million customers at the end of 2010. Increases in direct sales volume were partially offset by lower unit prices.
The decrease in POLR and structured sales revenues of $1.6 billion was due to lower sales volumes to Met-Ed, Penelec and the Ohio Companies, partially offset by increased sales to non-affiliates and higher unit prices to the Pennsylvania Companies. The decline in POLR sales reflects our focus on more profitable sales channels.
Wholesale revenues increased $60 million due to higher wholesale prices partially offset by decreased volumes. The lower sales volumes were the result of decreased short-term (net hourly positions) transactions in MISO, partially offset by increased short-term transactions in PJM. In addition, capacity revenues earned by units that moved to PJM from MISO were partially offset by losses on financially settled sales contracts.



62


The following tables summarize the price and volume factors contributing to changes in revenues from generation sales:
Source of Change in Direct and Governmental Aggregation Increase(Decrease)
  (In millions)
Direct Sales:  
Effect of increase in sales volumes $1,034
Change in prices (75)
  959
Governmental Aggregation:  
Effect of increase in sales volumes 319
Change in prices 14
  333
Net Increase in Direct and Government Aggregation Revenues $1,292
Source of Change in POLR and Structured Revenues 
Increase
(Decrease)
  (In millions)
Effect of decrease in sales volumes $(1,800)
Change in prices 155
  $(1,645)
   
Source of Change in Wholesale Revenues Increase(Decrease)
  (In millions)
Effect of decrease in sales volumes $(182)
Change in prices 242
  $60
Operating Expenses —
Total operating expenses increased $1.5 billion in 2011. Excluding the Allegheny companies, total operating expenses decreased $98 million compared to 2010, due to the following factors:
Fuel costs decreased $177 million in 2011 compared to 2010 primarily due to cash received from assigning a substantially below-market, long-term fossil contract to a third party. In connection with its merger integration initiatives and risk management strategy, FirstEnergy continues to evaluate opportunities with respect to its commodity contracts. As a result of the assignment, FirstEnergy entered into a new long-term contract with another supplier for replacement fuel based on current market prices. Excluding the assignment, fuel costs decreased $54 million in 2011 compared to 2010 due to decreased volumes consumed ($115 million), partially offset by higher unit prices ($61 million). The decrease in fossil fuel expense reflects lower generation needed to satisfy sales requirements. Lower fossil fuel expenses were partially offset by a $22 million increase in nuclear fuel costs, which rose principally due to higher nuclear fuel unit prices following the refueling outages that occurred in 2010 and 2011.
Purchased power costs decreased $382 million as lower volumes ($649 million) were partially offset by higher unit prices ($267 million). The decrease in volume primarily relates to the expiration at the end of 2010 of a 1,300 MW third party contract associated with serving Met-Ed and Penelec.
Fossil operating costs increased $36 million due primarily to higher labor, contractor and material costs resulting from an increase in planned and unplanned outages, which were partially offset by reduced losses from the sale of excess coal.
Nuclear operating costs increased $53 million primarily due to Perry and Beaver Valley Unit 2 refueling outages in 2011. While Davis-Besse had a refueling outage in 2010 and an outage in 2011 to replace the reactor vessel head, the work performed on both outages was largely capital-related.
Transmission expenses increased $249 million due primarily to higher congestion, network and line loss expenses.
Depreciation expense increased $20 million principally due to the completion of the Sammis projects at the end of 2010.
General taxes increased $36 million due to an increase in revenue-related taxes.


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Impairments of long-lived assets decreased $85 million compared to last year. The 2011 charges are due to the pending shutdown of six unregulated, coal-fired generating units; charges in 2010 related to operational changes at certain smaller coal-fired units.
Other operating expenses increased $152 million primarily due to a $54 million provision for excess and obsolete material relating to revised inventory practices adopted in connection with the Allegheny merger; a $64 million increase in pensions and OPEB mark-to-market adjustment charges from higher net actuarial losses; a $10 million increase in other mark-to-market adjustments; an $18 million increase in agent fees due to rapid growth in FES' retail business; and a $17 million increase in intercompany billings. The intercompany billings increased due to higher merger-related costs, partially offset by lower leasehold costs from the Ohio Companies.
The inclusion of the Allegheny companies' operations added $1.6 billion to operating expenses as shown in the following table:
Source of Operating Expense Changes Increase (Decrease)
  (In millions)
Allegheny Companies  
Fuel $794
Purchased power 149
Fossil operation and maintenance 152
Transmission 198
Pensions and OPEB mark-to-market adjustment 44
Other mark-to-market 4
Depreciation 111
General taxes 40
Other 96
Total operating expenses $1,588
Other Expense —
Total other expense in 2011 was $453 million lower than 2010, primarily due to a $569 million gain on the partial sale of FEV's interest in Signal Peak and an increase in nuclear decommissioning trust investment income of $5 million, partially offset by a $121 million increase in net interest expense. The net interest expense increase in 2011 from 2010 resulted from lower capitalized interest due to the completion of major environmental projects in 2010.
Other — 2011 Compared to 2010
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 an $99 million decrease in earnings available to FirstEnergy in 2011 compared to 2010. The decrease resulted primarily from decreased capitalized interest and increased depreciation expense resulting from the completed construction projects placed into service ($58 million), decreased investment income ($16 million), an asset impairment charge in the first quarter of 2011 ($11 million) and higher income taxes ($13 million).
Summary of Results of Operations — 2010 Compared with 2009
Financial results for FirstEnergy’s major business segments in 2010 and 2009 were as follows:


64


2010 Financial Results Regulated Distribution Competitive Energy Services Regulated Independent Transmission Other and Reconciling Adjustments FirstEnergy Consolidated
  (In millions)
Revenues:          
External          
Electric $9,271
 $3,252
 $—
 $—
 $12,523
Other 300
 323
 242
 (123) 742
Internal 139
 2,301
 —
 (2,366) 74
Total Revenues 9,710
 5,876
 242
 (2,489) 13,339
           
Operating Expenses:          
Fuel —
 1,432
 —
 —
 1,432
Purchased power 5,273
 1,724
 —
 (2,373) 4,624
Other operating expenses 1,320
 1,393
 61
 (78) 2,696
Pensions and OPEB mark-to-market adjustment 82
 107
 (2) 3
 190
Provision for depreciation 433
 284
 37
 14
 768
Amortization of regulatory assets, net 712
 —
 10
 —
 722
General taxes 605
 124
 30
 17
 776
Impairment of long-lived assets —
 388
 —
 —
 388
Total Operating Expenses 8,425
 5,452
 136
 (2,417) 11,596
           
Operating Income 1,285
 424
 106
 (72) 1,743
           
Other Income (Expense):          
Investment income 102
 51
 —
 (36) 117
Interest expense (500) (232) (22) (91) (845)
Capitalized interest 4
 95
 2
 64
 165
Total Other Expense (394) (86) (20) (63) (563)
           
Income Before Income Taxes 891
 338
 86
 (135) 1,180
Income taxes 338
 128
 32
 (36) 462
Net Income 553
 210
 54
 (99) 718
Loss attributable to noncontrolling interest —
 —
 —
 (24) (24)
Earnings available to FirstEnergy Corp. $553
 $210
 $54
 $(75) $742



65


2009 Financial Results Regulated Distribution Competitive Energy Services Regulated Independent Transmission Other and Reconciling Adjustments FirstEnergy Consolidated
  (In millions)
Revenues:          
External          
Electric $10,585
 $1,447
 $—
 $—
 $12,032
Other 331
 481
 223
 (111) 924
Internal —
 2,843
 —
 (2,826) 17
Total Revenues 10,916
 4,771
 223
 (2,937) 12,973
           
Operating Expenses:          
Fuel —
 1,153
 —
 —
 1,153
Purchased power 6,560
 996
 —
 (2,826) 4,730
Other operating expenses 1,257
 1,332
 56
 (94) 2,551
Pensions and OPEB mark-to-market adjustment 166
 151
 2
 2
 321
Provision for depreciation 426
 279
 37
 15
 757
Amortization of regulatory assets, net 1,006
 —
 13
 —
 1,019
General taxes 589
 112
 32
 20
 753
Impairment of long-lived assets —
 6
 —
 —
 6
Total Operating Expenses 10,004
 4,029
 140
 (2,883) 11,290
           
Operating Income 912
 742
 83
 (54) 1,683
           
Other Income (Expense):          
Investment income 141
 121
 —
 (58) 204
Interest expense (478) (174) (19) (307) (978)
Capitalized interest 3
 62
 1
 65
 131
Total Other Expense (334) 9
 (18) (300) (643)
           
Income Before Income Taxes 578
 751
 65
 (354) 1,040
Income taxes 243
 305
 26
 (390) 184
Net Income 335
 446
 39
 36
 856
Loss attributable to noncontrolling interest —
 —
 —
 (16) (16)
Earnings available to FirstEnergy Corp. $335
 $446
 $39
 $52
 $872


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Changes Between 2010 and 2009 Financial Results
Increase (Decrease)
 Regulated Distribution Competitive Energy Services Regulated Independent Transmission Other and Reconciling Adjustments FirstEnergy Consolidated
  (In millions)
Revenues:          
External          
Electric $(1,314) $1,805
 $—
 $—
 $491
Other (31) (158) 19
 (12) (182)
Internal 139
 (542) —
 460
 57
Total Revenues (1,206) 1,105
 19
 448
 366
           
Operating Expenses:          
Fuel —
 279
 —
 —
 279
Purchased power (1,287) 728
 —
 453
 (106)
Other operating expenses 63
 61
 5
 16
 145
Pensions and OPEB mark-to-market adjustment (84) (44) (4) 1
 (131)
Provision for depreciation 7
 5
 —
 (1) 11
Amortization of regulatory assets, net (294) —
 (3) —
 (297)
General taxes 16
 12
 (2) (3) 23
Impairment of long-lived assets —
 382
 —
 —
 382
Total Operating Expenses (1,579) 1,423
 (4) 466
 306
           
Operating Income 373
 (318) 23
 (18) 60
           
Other Income (Expense):          
Gain on partial sale of Signal Peak —
 —
 —
 —
 —
Investment income (39) (70) —
 22
 (87)
Interest expense (22) (58) (3) 216
 133
Capitalized interest 1
 33
 1
 (1) 34
Total Other Expense (60) (95) (2) 237
 80
           
Income Before Income Taxes 313
 (413) 21
 219
 140
Income taxes 95
 (177) 6
 354
 278
Net Income 218
 (236) 15
 (135) (138)
Loss attributable to noncontrolling interest —
 —
 —
 (8) (8)
Earnings available to FirstEnergy Corp. $218
 $(236) $15
 $(127) $(130)
Regulated Distribution — 2010 Compared with 2009
Net income increased by $218 million in 2010 compared to 2009, primarily due to CEI’s $216 million regulatory asset impairment in 2009 and lower pensions and OPEB costs, partially offset by increases in other operating expenses. Lower generation revenues were offset by lower purchased power expenses.


67


Revenues —
The decrease in total revenues resulted from the following sources:
Revenues by Type of Service 2010 2009 
Increase
(Decrease)
  (In millions)
Distribution services $3,629
 $3,419
 $210
Generation:      
Retail 4,457
 5,764
 (1,307)
Wholesale 702
 752
 (50)
Total generation sales 5,159
 6,516
 (1,357)
Transmission 596
 805
 (209)
Other 326
 176
 150
Total Revenues $9,710
 $10,916
 $(1,206)
The increase in distribution deliveries by customer class is summarized in the following table:
Electric Distribution MWH DeliveriesIncrease
Residential5.9%
Commercial2.8%
Industrial8.4%
Total Distribution MWH Deliveries5.6%
Higher deliveries to residential and commercial customers reflect increased weather-related usage due to a 70% increase in cooling degree days in 2010 compared to 2009, partially offset by a 4% decrease in heating degree days for the same period. In the industrial sector, MWH deliveries increased primarily to major automotive customers (16%), refinery customers (7%) and steel customers (38%). The increase in distribution service revenues also reflects Met-Ed's, Penelec's and Penn's recovery of the Pennsylvania EE&C 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 $1.4 billion decrease in generation revenues in 2010 compared to 2009:
Source of Change in Generation Revenues 
Increase
(Decrease)
  (In millions)
Retail:  
Effect of decrease in sales volumes $(1,435)
Change in prices 128
  (1,307)
Wholesale:  
Effect of decrease in sales volumes (64)
Change in prices 14
  (50)
Net Decrease in Generation Revenues $(1,357)
The decrease in retail generation sales volumes was primarily due to an increase in customer shopping in the Ohio Companies’ service territories. Total generation MWH provided by alternative suppliers as a percentage of total MWH deliveries by the Ohio Companies increased to 62% in 2010 from 17% in 2009.
The decrease in wholesale generation revenues reflected lower RPM revenues for Met-Ed and Penelec in the PJM market.
Transmission revenues decreased $209 million primarily due to the termination of the Ohio Companies’ transmission tariff effective June 1, 2009; transmission costs are now a component of the cost of generation established under the May 2009 Ohio CBP.
Other revenues increased by $150 million primarily due to Met-Ed's and Penelec's PSA with FES in 2010, resulting in increased capacity revenues.


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Operating Expenses —
Total operating expenses decreased by $1.6 billion due to the following:
Purchased power costs were $1.3 billion lower in 2010, largely due to lower volume requirements. 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 increase in customer shopping in the Ohio Companies’ service territories. The decrease in purchases from FES also resulted from the increase in customer shopping in Ohio.
An increase in purchased power unit costs from non-affiliates in 2010 resulted from higher capacity prices in the PJM market for Met-Ed and Penelec. A decrease in unit costs for purchases from FES was principally due to the lower weighted average unit price per MWH established under the May 2009 CBP auction for the Ohio Companies effective June 1, 2009.
Source of Change in Purchased Power 
Increase
(Decrease)
  (In millions)
Purchases from non-affiliates:  
Change due to increased unit costs $709
Change due to decreased volumes (1,489)
  (780)
Purchases from FES:  
Change due to decreased unit costs (257)
Change due to decreased volumes (250)
  (507)
Net Decrease in Purchased Power Costs $(1,287)
Transmission expenses increased $70 million primarily due to higher PJM network transmission expenses and congestion costs for Met-Ed and Penelec, partially offset by lower MISO network transmission expenses that are reflected in the generation rate established under the May 2009 Ohio CBP. Met-Ed and Penelec defer or amortize the difference between revenues from their transmission rider and transmission costs incurred, resulting in no material effect on current period earnings.
Energy efficiency program costs, which are also recovered through rates, increased $41 million in 2010 compared to 2009.
Labor and employee benefit expenses decreased by $30 million due to lower payroll costs resulting from staffing reductions implemented in 2009, and restructuring expenses recognized in 2009.
Pensions and OPEB mark-to-market adjustment charges decreased by $84 million primarily resulting from lower net actuarial losses.
Expenses for economic development commitments related to the Ohio Companies’ ESP were lower by $11 million in 2010 compared to 2009.
Depreciation expense increased $7 million due to property additions since 2009.
Amortization of regulatory assets decreased $294 million due primarily to the absence of the $216 million impairment of CEI’s regulatory assets in 2009, reduced net MISO and PJM transmission cost amortization and reduced CTC amortization for Met-Ed and Penelec, partially offset by increased amortization associated with the accelerated recovery of deferred distribution costs in Ohio and a $35 million regulatory asset impairment in 2010 associated with the Ohio Companies’ ESP and the absence of CEI’s purchased power cost deferrals that ended in early 2009.
General taxes increased $16 million principally due to a benefit relating to Ohio MWH excise taxes that was recognized in 2009 and applicable to prior years.
Other Expense —
Other expense increased $60 million in 2010 compared to 2009 primarily due to lower investment income on OE's and TE's nuclear decommissioning trusts ($37 million) and higher net interest expense associated with debt issuances during 2009 ($23 million).
Regulated Independent Transmission — 2010 Compared with 2009
Net income increased by $15 million in 2010 compared to 2009 due to increased revenues.


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Revenues —
Total revenues increased by $19 million principally due to higher peak loads in 2010 compared to 2009.
Operating Expenses —
Total operating expenses decreased by $4 million principally due to decreased property taxes and decreased pensions and OPEB costs primarily due to lower net actuarial losses.
Other Expense —
Other expense increased $2 million in 2010 due to higher interest expense associated with higher average debt levels in 2010 compared to 2009.
Competitive Energy Services — 2010 Compared to 2009
Net income decreased by $235 million in 2010 compared to 2009. The decrease in net income was primarily due to $382 million of impairment charges ($240 million net of tax) in 2010. In addition, FES sold a 6.65% participation interest in OVEC in 2010 compared to a 9% interest in 2009, accounting for $105 million of the reduction in net income. Investment income from nuclear decommissioning trusts was also lower in 2010. These reductions were partially offset by an increase in sales margins.
Revenues —
Total revenues increased $1.1 billion in 2010 compared to the same period in 2009 primarily due to an increase in direct and governmental aggregation sales and sales of RECs, partially offset by decreases in POLR sales to the Ohio Companies, other wholesale sales and the reduced OVEC participation interest sale in 2010.
The increase in reported segment revenues resulted from the following sources:
Revenues by Type of Service 2010 2009 Increase (Decrease)
  (In millions)
Direct and Governmental Aggregation $2,493
 $779
 $1,714
POLR 2,589
 2,863
 (274)
Wholesale 397
 632
 (235)
Transmission 77
 73
 4
RECs 74
 17
 57
Sale of OVEC participation interest 85
 252
 (167)
Other 161
 155
 6
Total Revenues $5,876
 $4,771
 $1,105
The increase in direct and governmental aggregation revenues of $1.7 billion resulted from increased revenue from the acquisition of new commercial and industrial customers as well as from new governmental aggregation contracts with communities in Ohio that provide generation to 1.5 million residential and small commercial customers at the end of 2010 compared to approximately 600,000 customers at the end of 2009. Increases in direct sales were partially offset by lower unit prices. Sales to residential and small commercial customers were also bolstered by summer weather in the delivery area that was significantly warmer than in 2009.
The decrease in POLR revenues of $274 million was due to lower sales volumes and lower unit prices to the Ohio Companies, partially offset by increased sales volumes and higher unit prices to Met-Ed and Penelec. The lower sales volumes and unit prices to the Ohio Companies in 2010 reflected the results of the May 2009 CBP. The increased revenues to Met-Ed and Penelec resulted from FES supplying volumes previously supplied through a third-party contract, and at prices that were slightly higher than in 2009.
Other wholesale revenues decreased $235 million due to reduced volumes, partially offset by higher prices. Lower sales volumes in MISO were due to available capacity serving increased retail sales in Ohio partially offset by increased sales under bilateral agreements in PJM.


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The following tables summarize the price and volume factors contributing to changes in revenues from generation sales:
Source of Change in Direct and Governmental Aggregation Increase (Decrease)
  (In millions)
Direct Sales:  
Effect of increase in sales volumes $1,080
Change in prices (87)
  993
Government Aggregation:  
Effect of increase in sales volumes 707
Change in prices 14
  721
Net Increase in Direct and Governmental Aggregation Revenues $1,714
Source of Change in Wholesale Revenues Increase (Decrease)
  (In millions)
POLR:  
Effect of increase in sales volumes $38
Change in prices (312)
  (274)
Other Wholesale:  
Effect of decrease in sales volumes (344)
Change in prices 109
  (235)
Net Decrease in Wholesale Revenues $(509)
Operating Expenses —
Total operating expenses increased $1.4 billion in 2010 due to the following factors:
Fuel costs increased $279 million in 2010 compared to 2009 primarily due to increased volumes consumed ($217 million) and higher unit prices ($62 million). The higher volumes consumed in 2010 were due to increased sales to direct and governmental aggregation customers, improved economic conditions and improved generating unit availability. The increase in unit prices was due primarily to increased coal transportation costs and to higher nuclear fuel unit prices following the refueling outages that occurred in 2009 and 2010.
Purchased power costs increased $728 million. Increased volumes purchased primarily relate to the assumption of a 1,300 MW third party contract from Met-Ed and Penelec.
Fossil operating costs decreased $12 million due primarily to lower labor and professional and contractor costs, which were partially offset by reduced gains from the sale of emission allowances and excess coal.
Nuclear operating costs decreased $21 million due primarily to lower labor, consulting and contractor costs partially offset by increased nuclear property insurance and employee benefit costs. The year 2010 had one less refueling outage and fewer extended outages than the same period of 2009.
Transmission expenses increased $25 million due primarily to increased costs in MISO of $170 million from higher network, ancillary and congestion costs, partially offset by lower PJM transmission expenses of $145 million due to lower congestion costs.
Depreciation expense increased $5 million principally due to property additions that were placed in service since 2009.
General taxes increased $12 million due to an increase in revenue-related taxes.
Other operating expenses increased $406 million primarily due to a $382 million impairment charge ($240 million net of tax) related to operational changes at certain smaller coal-fired units. Expenses also increased for professional and contractor services, billings from affiliated service companies, uncollectible customer accounts and agent fees, as FES continued to grow its retail business.


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Other Expense —
Total other expense in 2010 was $95 million higher than the same period in 2009, primarily due to a $66 million decrease in nuclear decommissioning trust investment income and a $25 million increase in net interest expense from new long-term debt issued in late 2009 combined with the restructuring of outstanding PCRBs that occurred throughout 2009 and 2010.
Other — 2010 Compared to 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 $127 million decrease in earnings available to FirstEnergy in 2010 compared to 2009. The decrease resulted primarily from increased income tax expense ($354 million) due in part to the absence of favorable tax settlements that occurred in 2009 ($200 million), partially offset by the absence of 2009 debt retirement costs in connection with the tender offer for holding company debt ($90 million),decreased interest expense associated with the debt retirement ($53 million) and increased investment income ($22 million).
CAPITAL RESOURCES AND LIQUIDITY
As of December 31, 2011, FirstEnergy had $202 million of cash and cash equivalents available to fund investments, operations and capital expenditures.
FirstEnergy expects its existing sources of liquidity to remain sufficient to meet its anticipated obligations and those of its subsidiaries. FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. In addition to internal sources to fund liquidity and capital requirements for 2012 and beyond, FirstEnergy expects to rely on external sources of funds. Short-term cash requirements not met by cash provided from operations are generally satisfied through short-term borrowings. Long-term cash needs may be met through issuances of debt and/or equity securities. FirstEnergy expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements along with continued access to long-term capital markets.
A material adverse change in operations, or in the availability of external financing sources, could impact FirstEnergy’s liquidity position and ability to fund its capital requirements. To mitigate risk, FirstEnergy’s business strategy stresses financial discipline and a strong focus on execution. Major elements include the expectation of: adequate cash from operations, opportunities for favorable long-term earnings growth in the competitive generation markets, operational excellence, business plan execution, well-positioned generation fleet, no speculative trading operations, appropriate long-term commodity hedging positions, manageable capital expenditure program, adequately funded pension plan, minimal near-term maturities of existing long-term debt, commitment to a secure dividend and a successful merger integration.
As of December 31, 2011, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was principally due to currently payable long-term debt, which, as of December 31, 2011, included the following:
Currently Payable Long-term Debt (In millions)
Met-Ed, Penelec, FGCO and NGC PCRBs supported by bank LOCs (1)
 $632
AE Supply unsecured note 503
FGCO and NGC unsecured PCRBs (1)
 270
WP unsecured note 80
NGC collateralized lease obligation bonds 67
Sinking fund requirements 52
Other notes 17
  $1,621
(1)
These PCRBs are classified as currently payable long-term debt solely because the applicable Interest rate mode permits individual debt holders to put the respective debt back to the issuer prior to maturity.


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Short-Term Borrowings
FirstEnergy hadnosignificant short-term borrowings as of December 31, 2011, and short-term borrowings of approximately $700 millionas ofDecember 31, 2010. FirstEnergy’s available liquidity as of January 31, 2012, was as follows:
Company Type Maturity Commitment Available Liquidity
      (In millions)
FirstEnergy(1)
 Revolving June 2016 $2,000
 $1,395
FES / AE Supply Revolving June 2016 2,500
 2,498
TrAIL Revolving Jan. 2013 450
 450
AGC Revolving Dec. 2013 50
 —
    Subtotal $5,000
 $4,343
    Cash —
 49
    Total $5,000
 $4,392
(1)
FE and the Utilities
Revolving Credit Facilities
FirstEnergy and FES / AE Supply Facilities
FirstEnergy and certain of its subsidiaries participate in two five-year syndicated revolving credit facilities with aggregate commitments of$4.5 billion(Facilities).
An aggregate amount of$2 billionis available to be borrowed under a syndicated revolving credit facility (FirstEnergy Facility), subject to separate borrowing sublimits for each borrower. The borrowers under the FirstEnergy Facility are FE, OE, Penn, CEI, TE, Met-Ed, ATSI, JCP&L, MP, Penelec, PE and WP. An additional$2.5 billionis available to be borrowed by FES and AE Supply under a separate syndicated revolving credit facility (FES/AE Supply Facility), subject to separate borrowing sublimits for each borrower.
Commitments under each of the Facilities will be available until June 17, 2016, unless the lenders agree, at the request of the applicable borrowers, to up to two additional one-year extensions. Generally, borrowings under each of the Facilities are available to each borrower separately and mature on the earlier of364days from the date of borrowing or the commitment termination date, as the same may be extended.
Borrowings under each of the Facilities are subject to the usual and customary provisions for acceleration upon the occurrence of events of default, including a cross-default for other indebtedness in excess of$100 million, as described further in Note 12, Capitalization.
The following table summarizes the borrowing sub-limits for each borrower under the Facilities, 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 ofDecember 31, 2011:


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Borrower Revolving Credit Facility Sub-Limit Regulatory and Other Short-Term Debt Limitations 
  (In millions) 
FE  $2,000
  —
(1) 
FES  $1,500
  —
(2) 
AE Supply  $1,000
  —
(2) 
OE  $500
  $500
 
CEI  $500
  $500
 
TE  $500
  $500
 
JCP&L  $425
  $411
(3) 
Met-Ed  $300
  $300
(3) 
Penelec  $300
  $300
(3) 
West Penn  $200
  $200
(3) 
MP  $150
  $150
(3) 
PE  $150
  $150
(3) 
ATSI  $100
  $100
 
Penn  $50
  $33
(3) 
(1)
No limitations.
(2)
No limitation based upon blanket financing authorization from the FERC under existing open market tariffs.
(3)
Excluding amounts which may be borrowed under the regulated companies’ money pool.
The entire amount of the FES/AE Supply Facility and$700 millionof the FirstEnergy Facility, subject to each borrower’s sub-limit, is available for 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 each of the Facilities and against the applicable borrower’s borrowing sub-limit.
Each of the Facilities 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 December 31, 2011, FirstEnergy’s and its subsidiaries’ debt to total capitalization ratios (as defined under each of the Facilities) were as follows:
Borrower
FirstEnergy57.5%
FES51.4%
OE63.4%
Penn42.8%
CEI59.4%
TE62.7%
JCP&L43.6%
Met-Ed56.0%
Penelec56.6%
ATSI48.6%
MP56.6%
PE56.8%
WP52.1%
AE Supply38.5%
As of December 31, 2011, FirstEnergy could issue additional debt of approximately $6.7 billion, or recognize a reduction in equity of approximately $3.6 billion, and remain within the limitations of the financial covenants required by its revolving credit facility.
The Facilities do not contain provisions that restrict the ability to borrow or accelerate payment of outstanding advances as a result of any change in credit ratings. Pricing is subject to “pricing grids,” whereby the borrower's cost of funds borrowed under the Facilities is related to the credit ratings of the company borrowing the funds.


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AGC and TrAIL Revolving Credit Facilities
FirstEnergy also has established$500 millionof revolving credit facilities that are available to TrAIL ($450 million) and AGC($50 million) until January 2013 and December 2013, respectively.
Under the terms of its credit facility, outstanding debt of AGC may not exceed 65% of the sum of its debt and equity as of the last day of each calendar quarter. Outstanding debt for TrAIL may not exceed 65% of the sum of its debt and equity as of the last day of each calendar quarter through December 31, 2012. These provisions limit debt levels of these subsidiaries and also limit the net assets of each subsidiary that may be transferred to AE. As of December 31, 2011, the debt to total capitalization ratios for TrAIL and AGC (as defined under each of their credit facilities) were 48% and 51%, respectively.

As of December 31, 2011, TrAIL could issue additional debt of approximately $222 million, or recognize a reduction in equity of approximately $341 million and AGC could issue additional debt of approximately $39 million, or recognize a reduction in equity of approximately $61 million, and remain within the limitations of the financial covenants required by their credit facilities.
FirstEnergy Money Pools
FirstEnergy’s regulated companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy’s unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool.The average interest rate for borrowings during 2011 was0.44% per annum for the regulated companies’ money pool and0.42% per annum for the unregulated companies’ money pool.
Pollution Control Revenue Bonds
As of December 31, 2011, FirstEnergy’s currently payable long-term debt included approximately $632 million (FES — $558 million, 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 as of December 31, 2011:
LOC Bank 
Aggregate LOC
Amount(1)
 LOC Termination Date 
Reimbursements
of LOC Draws Due
  (In millions)    
UBS $272
 April 2014 April 2014
CitiBank N.A. 165
 June 2014 June 2014
Wachovia Bank 153
 March 2014 March 2014
The Bank of Nova Scotia 49
 April 2014 
Multiple dates(2)
Total $639
    
(1)
Includes approximately $7 million of applicable interest coverage.
(2)
Shorter of 6 months or LOC termination date.
During 2011, FirstEnergy redeemed or repurchased approximately $520.4 million principal amount of PCRBs, as summarized in the following table. Approximately $28.5 million of FGCO FMBs and $98.9 million of NGC FMBs associated with the PCRBs were returned for cancellation by the associated LOC providers.
SubsidiariesAmount 
 (In millions) 
AE Supply$53.0
(1) 
FGCO$198.2
(2) 
NGC$213.5
(2) 
MP$70.2
(1) 
(1)
Includes $14.4 million of PCRBs redeemed for which MP and AE Supply are co-obligors.
(2)
Subject to market conditions, these PCRBs are being held for future remarketing.


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Long-Term Debt Capacity
As ofDecember 31, 2011, the Ohio Companies and Penn had the aggregate capability to issue approximately$2.7 billionof 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$232 millionand$20 million, respectively. As a result of the indenture provisions, TE cannot incur any additional secured debt. Met-Ed and Penelec had the capability to issue secured debt of approximately$376 millionand$382 million, respectively, under provisions of their senior note indentures as ofDecember 31, 2011. In addition, based upon their respective FMB indentures, net earnings and available bondable property additions as ofDecember 31, 2011, MP, PE and WP had the capability to issue approximately$1.1 billionof additional FMBs in the aggregate. These companies may be further limited by the financial covenants of the Facilities and subject to current regulatory approvals and applicable statutory and/or charter limitations.
Based upon FGCO’s net earnings and available bondable property additions under its FMB indentures as ofDecember 31, 2011, FGCO had the capability to issue$2.1 billionof additional FMBs under the terms of that indenture. Based upon NGC’s net earnings and available bondable property additions under its FMB indenture as ofDecember 31, 2011, NGC had the capability to issue$2.0 billionof additional FMBs under the terms of that indenture.
FirstEnergy’s access to capital markets and costs of financing are influenced by the credit ratings of its securities. On March 21, 2011, S&P affirmed the ratings and stable outlook of FirstEnergy and its subsidiaries. On May 27, 2011, Fitch upgraded ratings for certain subsidiaries and revised the outlook to stable from negative for FirstEnergy and FES. On August 18, 2011, Moody's downgraded ratings for FES to Baa3 from Baa2 and revised FES' outlook to stable. On January 18, 2012, Moody's upgraded ratings for TrAIL to A3 from Baa2. The following table displays FirstEnergy’s and its subsidiaries’ debt credit ratings as of February 24, 2012:
Senior SecuredSenior Unsecured
IssuerS&PMoody’sFitchS&PMoody’sFitch
FE———BB+Baa3BBB
FES———BBB-Baa3BBB
AE Supply———BBB-Baa3BBB-
AGC———BBB-Baa3BBB
ATSI———BBB-Baa1A-
CEIBBBBaa1BBBBBB-Baa3BBB-
JCP&L———BBB-Baa2BBB+
Met-EdBBBA3A-BBB-Baa2BBB+
MPBBB+Baa1A-BBB-Baa3BBB+
OEBBBA3BBB+BBB-Baa2BBB
PenelecBBBA3BBB+BBB-Baa2BBB
PennBBB+A3BBB+———
PEBBB+Baa1A-BBB-Baa3BBB+
TEBBBBaa1BBB———
TrAIL———BBB-A3A-
WPBBB+A3A-BBB-Baa2BBB+
See Note 12, Capitalization of the Combined Notes to the Consolidated Financial Statements for additional information on FirstEnergy's and the Registrants' long-term debt and other long-term obligations that were outstanding as of December 31, 2011.
Changes in Cash Position
As of December 31, 2011, FirstEnergy had $202 million of cash and cash equivalents compared to approximately $1 billion as of December 31, 2010. As of December 31, 2011 and 2010, FirstEnergy had approximately $79 million and $13 million, respectively, of restricted cash included in other current assets on the Consolidated Balance Sheet.
During 2011, FirstEnergy received $1.8 billion of cash dividends from its subsidiaries and paid$881 millionin cash dividends to common shareholders, including $20 million paid in March by AE to its former shareholders.


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Cash Flows From Operating Activities
FirstEnergy’s consolidated net cash from operating activities is provided primarily by its regulated distribution, regulated independent transmission and competitive energy services businesses (see Results of Operations above). Net cash provided from operating activities was $3.1 billion in 2011, $3.1 billion in 2010 and $2.5 billion in 2009, as summarized in the following table:
Operating Cash Flows 2011 2010 2009
  (In millions)
Net income $869
 $718
 $856
Non-cash charges 2,424
 2,343
 2,095
Pension trust contributions (372) —
 (500)
Working capital and other 142
 15
 14
  $3,063
 $3,076
 $2,465
The 2011 increase in non-cash charges is primarily due to increased pensions and OPEB mark-to-market adjustment charges from higher actuarial losses ($317 million), increased deferred taxes resulting from bonus depreciation ($348 million) and increased depreciation attributable to the acquired Allegheny companies ($353 million). These increases were partially offset by gains from the sale of assets, mostly due to the sale of Signal Peak ($543 million), and lower amortization of regulatory assets from reduced net PJM transmission cost and transition cost recovery ($393 million).
The 2011 increase in cash flows from working capital and other is primarily due to decreased receivables from higher customer collections ($324 million) partially offset by the absence of interest rate swap activity transacted in 2010 ($129 million).
Cash Flows From Financing Activities
In 2011, cash used for financing activities was $2,924 million compared to $983 million in 2010. The following table summarizessecurity issuances (net of any discounts) and redemptions:
Securities Issued or Redeemed 2011 2010 2009
    (In millions)  
New Issues      
PCRBs $272
 $740
 $940
Long-term revolving credit 70
 —
 —
Senior secured notes —
 350
 297
FMBs —
 —
 398
Unsecured Notes 262
 9
 2,997
  $604
 $1,099
 $4,632
Redemptions      
PCRBs $792
 $741
 $884
Long-term revolving credit 495
 —
 —
Senior secured notes 460
 141
 217
FMBs 15
 32
 1
Unsecured notes 147
 101
 1,508
  $1,909
 $1,015
 $2,610
       
Net repayment of short-term borrowings $(700) $(378) $(1,246)
Cash Flows From Investing Activities
Cash used for investing activities in 2011 resulted from cash used for property additions, partially offset by the cash acquired in the Allegheny merger and proceeds from asset sales. The following table summarizes investing activities for 2011, 2010 and 2009 by business segment:


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Summary of Cash Flows
Provided from (Used for) Investing Activities
 
Property
Additions
 Investments Other Total
    (In millions)  
Sources (Uses)        
2011        
Regulated distribution $(1,060) $30
 $(83) $(1,113)
Competitive energy services (927) 545
 3
 (379)
Regulated independent transmission (192) —
 (3) (195)
Cash received in Allegheny merger —
 590
 —
 590
Other and reconciling adjustments (99) 223
 17
 141
Total $(2,278) $1,388
 $(66) $(956)
         
2010        
Regulated distribution $(681) $96
 $17
 $(568)
Competitive energy services (1,159) (43) (51) (1,253)
Regulated independent transmission (64) —
 (4) (68)
Other and reconciling adjustments (59) (30) 30
 (59)
Total $(1,963) $23
 $(8) $(1,948)
         
2009        
Regulated distribution $(718) $39
 $(45) $(724)
Competitive energy services (1,412) (8) (19) (1,439)
Regulated independent transmission (32) —
 (1) (33)
Other and reconciling adjustments (41) (27) 79
 11
Total $(2,203) $4
 $14
 $(2,185)
Net cash used for investing activities in 2011 decreased by $992 million compared to 2010. The decrease was principally due to cash acquired in the Allegheny merger ($590 million) and an increase in proceeds from asset sales ($723 million), partially offset by increased property additions ($315 million).
Our capital spending for 2012 is expected to be approximately$2.1 billion(excluding nuclear fuel).For 2013, we anticipate baseline capital expenditures of approximately $2.0 billion, which exclude any potential additional strategic opportunities, future mandated spending, energy efficiency or environmental spending relating to MATS. Planned capital initiatives are intended to promote reliability, improve operations, and support current environmental and energy efficiency directives.Our capital investments for additional nuclear fuel are expected to be $280 million and $219 million in 2012 and 2013, respectively.
CONTRACTUAL OBLIGATIONS
As of December 31, 2011, our estimated cash payments under existing contractual obligations that we consider firm obligations are as follows:
Contractual Obligations Total 2012 2013-2014 2015-2016 Thereafter
  (In millions)
Long-term debt(1)
 $17,005
 $1,605
 $2,192
 $2,688
 $10,520
Interest on long-term debt(2)
 12,071
 975
 1,804
 1,548
 7,744
Operating leases(3)
 3,147
 258
 492
 598
 1,799
Fuel and purchased power(4)
 32,877
 3,598
 5,589
 4,616
 19,074
Capital expenditures 2,715
 681
 984
 638
 412
Pension funding 1,030
 —
 231
 799
 —
Other(5)
 263
 28
 105
 47
 83
Total $69,108
 $7,145
 $11,397
 $10,934
 $39,632
(1)
Excludes unamortized discounts and premiums and fair value accounting adjustments.
(2)
Interest on variable-rate debt based on rates as of December 31, 2011.
(3)
See Note 6, Leases of the Combined Notes to the Consolidated Financial Statements.
(4)
Amounts under contract with fixed or minimum quantities based on estimated annual requirements.
(5)
Includes amounts for capital leases (see Note 6, Leases of the Combined Notes to the Consolidated Financial Statements) and contingent tax liabilities (see Note 5, Taxes of the Combined Notes to the Consolidated Financial Statements).


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Excluded from the data shown above are estimates for the cash outlays stemming from power purchase contracts entered into by most of the Utilities and under which they procure the power supply necessary to provide generation service to their customers who do not choose an alternative supplier. The exact amounts will be determined by future customer behavior and consumption levels, but based on numerous planning assumptions, management estimates an amount of $5.4 billion in 2012, $1.8 billion of which relates to contracts with FES.
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. 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 credit support to various providers for the financing or refinancing by subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements include provisions for parent guarantees, surety bonds and/or LOCs to be issued by FirstEnergy on behalf of one or more of its subsidiaries. Additionally, certain contracts may contain collateral provisions that are contingent upon either FirstEnergy's or its subsidiaries’ credit ratings.
As of December 31, 2011, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $3.7 billion, as summarized below:
Guarantees and Other Assurances Maximum Exposure
  (In millions)
FirstEnergy Guarantees on Behalf of its Subsidiaries  
Energy and Energy-Related Contracts(1)
 $268
LOC (long-term debt) - interest coverage(2)
 5
OVEC obligations 300
Other(3)
 301
  874
   
Subsidiaries’ Guarantees  
Energy and Energy-Related Contracts 141
LOC (long-term debt) - interest coverage(2)
 2
FES’ guarantee of NGC’s nuclear property insurance 79
FES’ guarantee of FGCO’s sale and leaseback obligations 2,286
Other 12
  2,520
   
Surety Bonds 151
LOCs(4)
 189
  340
Total Guarantees and Other Assurances $3,734
(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 $632 million is reflected in currently payable long-term debt on FirstEnergy's consolidated balance sheets.
(3)
Includes guarantees of $95 million for nuclear decommissioning funding assurances, $161 million supporting OE’s sale and leaseback arrangement, and $36 million for railcar leases.
(4)
Includes $36 million issued for various terms pursuant to capacity available under FirstEnergy’s revolving credit facility, $116 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $37 million pledged in connection with the sale and leaseback of Perry by OE.
Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of$151 millionprovide 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.
While the types of guarantees discussed above are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a senior unsecured credit rating downgrade to below S&P's BBB- and Moody's Baa3 and lower, or a “material adverse event,” the immediate posting of collateral or accelerated payments may be required of the subsidiary. As ofDecember 31, 2011, FirstEnergy’s exposure to additional credit contingent contractual obligations was$636 million, as shown below:


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Collateral Provisions FES AE Supply Utilities Total
  (In millions)
Credit rating downgrade to below investment grade (1)
 $468
 $8
 $57
 $533
Material adverse event (2)
 31
 60
 12
 103
Total $499
 $68
 $69
 $636
(1)
Includes $205 million and $47 million that are also considered accelerations of payment or funding obligations for FES and the Utilities, respectively.
(2)
Includes $31 million that is also considered an acceleration of payment or funding obligation at FES.

Certain bilateral non-affiliate contracts entered into by the Competitive Energy Services segment contain margining provisions that require posting of collateral. Based on FES' and AE Supply's power portfolios exposure as of December 31, 2011, FES and AE Supply have posted collateral of$88 millionand$1 million, respectively. Depending on the volume of forward contracts and future price movements, higher amounts for margining could be required.

Not included in the preceding information is potential collateral arising from the PSAs between FES or AE Supply and affiliated utilities in the Regulated Distribution Segment. As of December 31, 2011, neither FES nor AE Supply had any collateral posted with their affiliates. In the event of a senior unsecured credit rating downgrade to below S&P's BB- or Moody's Ba3, FES and AE Supply would be required to post$49 millionand$24 million, respectively.

FES' debt obligations are generally guaranteed by its subsidiaries, FGCO and NGC, and FES guarantees the debt obligations of each of FGCO and NGC. Accordingly, present and future holders of indebtedness of FES, FGCO and NGC would have claims against each of FES, FGCO and NGC, regardless of whether their primary obligor is FES, FGCO or NGC.
Signal Peak and Global Rail are borrowers under a $350 million syndicated two-year senior secured term loan facility due in October 2012. FirstEnergy, together with WMB Loan Ventures, LLC and WMB Loan Ventures II, LLC, the entities that previously shared ownership in the borrowers with FEV, have provided a guaranty of the borrowers' obligations under the facility. On October 18, 2011, FEV sold a portion of its ownership interest in Signal Peak and Global Rail (see Note 8, Variable Interest Entities). Following the sale, FirstEnergy, WMB Loan Ventures, LLC and WMB Loan Ventures II, LLC, together with Global Mining Group, LLC and Global Holding will continue to guarantee the borrowers' obligations until either the facility is replaced with non-recourse financing (no later than June 30, 2012) or replaced with appropriate recourse financing no earlier than September 4, 2012, that provides for separate guarantees from each owner in proportion with each equity owner's percentage ownership in the joint venture. In addition, FEV, Global Mining Group, LLC and Global Holding, the entities that own direct and indirect equity interests in the borrowers, have pledged those interests to the lenders under the current facility as collateral.
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, was $1.6 billion as of December 31, 2011. See Note 6, Leases of the Combined Notes to the Consolidated Financial Statements for further information on FirstEnergy's and the Registrants' leases.
MARKET RISK INFORMATION
FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.
Commodity Price Risk
FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. FirstEnergy's Risk Management 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 practice. FirstEnergy uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.
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 9, Fair Value Measurements of the Combined Notes to the Consolidated Financial Statements). Sources of information for the valuation of commodity derivative contracts assets and liabilities as of December 31, 2011 are summarized by year in the following table:


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Source of Information-
Fair Value by Contract Year
 2012 2013 2014 2015 2016 Thereafter Total
  (In millions)
Prices actively quoted(1)
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Other external sources(2)
 (211) (51) (32) (22) —
 —
 (316)
Prices based on models (21) —
 —
 —
 8
 31
 18
Total(3)
 $(232) $(51) $(32) $(22) $8
 $31
 $(298)
(1)
Represents exchange traded New York Mercantile Exchange futures and options.
(2)
Primarily represents contracts based on broker and IntercontinentalExchange quotes.
(3)
Includes $(301) million in non-hedge commodity derivative contracts that are primarily related to NUG contracts. NUG contracts are subject to regulatory accounting and do not materially impact earnings.
FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. Based on derivative contracts held as of December 31, 2011, an adverse 10% change in commodity prices would decrease net income by approximately $13 million during the next 12 months.
Interest Rate Risk
FirstEnergy’s exposure to fluctuations in market interest rates is reduced since a significant portion of debt has fixed interest rates, as noted in the table below. FirstEnergy is subject to the inherent interest rate risks related to refinancing maturing debt by issuing new debt securities. As discussed in Note 6, Leases of the Combined Notes to the Consolidated Financial Statements, FirstEnergy’s investments in capital trusts effectively reduce future lease obligations, also reducing interest rate risk.
Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income $89
 $100
 $110
 $76
 $23
 $2,008
 $2,406
 $2,456
Average interest rate 8.8% 8.9% 9.0% 9.5% 10.3% 5.4% 6.0%  
Liabilities:                
Long-term Debt:                
Fixed rate $751
 $964
 $866
 $1,330
 $891
 $11,628
 $16,430
 $18,585
Average interest rate 7.3% 5.9% 5.4% 4.7% 5.9% 6.2% 6.1%  
Variable rate 
 $150
 
 
 
 $585
 $735
 $735
Average interest rate   1.8%       0.1% 0.4%  
Equity Price Risk
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 provides a portion of non-contributory pre-retirement basic life insurance for employees who are eligible to retire. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.
The benefit plan assets and obligations are remeasured annually using a December 31 measurement date or as significant triggering events occur. As of December 31, 2011, the FirstEnergy pension plan was invested in approximately 19% of equity securities, 48% of fixed income securities, 21% of absolute return strategies, 6% of real estate, 2% of private equity and 4% of cash. A decline in the value of pension plan assets could result in additional funding requirements. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. During 2011, FirstEnergy made pre-tax contributions to its qualified pension plans of $372 million. FirstEnergy made an additional $600 million pre-tax contribution to the qualified pension plan on January 5, 2012.
NDT funds have been established to satisfy NGC’s and certain of the Utilities’ nuclear decommissioning obligations. As of December 31, 2011, approximately 79% of the funds were invested in fixed income securities, 12% of the funds were invested in equity


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securities and 9% were invested in short-term investments, with limitations related to concentration and investment grade ratings. The investments are carried at their market values of approximately $1,699 million, $258 million and $207 million for fixed income securities, equity securities and short-term investments, respectively, as of December 31, 2011, excluding ($52) million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $26 million reduction in fair value as of December 31, 2011. The decommissioning trusts of JCP&L, Met-Ed and Penelec 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 recognized in earnings the unrealized losses on available-for-sale securities held in their NDT as OTTI. A decline in the value of FirstEnergy’s NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During 2011, approximately $1 million, $4 million and $1 million was contributed to the NDTs of JCP&L, OE and TE, respectively. FENOC has submitted a $95 million parental guarantee to the NRC for a short-fall in nuclear decommissioning funding to Beaver Valley Unit 1 and Perry.
CREDIT RISK
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. FirstEnergy evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. FirstEnergy may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. FirstEnergy monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.
Wholesale Credit Risk
FirstEnergy measures wholesale credit risk as the replacement cost for derivatives in power, natural gas, coal and emission allowances, adjusted for amounts owed to or due from counterparties for settled transactions. The replacement cost of open positions represents unrealized gains, net of any unrealized losses, where FirstEnergy has a legally enforceable right of set-off. FirstEnergy monitors and manages the credit risk of wholesale marketing, risk management and energy transacting operations through credit policies and procedures, which include an established credit approval process, daily monitoring of counterparty credit limits, the use of credit mitigation measures such as margin, collateral and the use of master netting agreements. FirstEnergy aggressively manages the quality of its portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB (S&P).
Retail Credit Risk
FirstEnergy is exposed to retail credit risk through competitive electricity activities, which serve residential, commercial and industrial companies. Retail credit risk results when customers default on contractual obligations or fail to pay for service rendered. This risk represents the loss that may be incurred due to the nonpayment of customer accounts receivable balances, as well as the loss from the resale of energy previously committed to serve customers.
Retail credit risk is managed through established credit approval policies, monitoring customer exposures and the use of credit mitigation measures such as deposits in the form of LOCs, cash or prepayment arrangements.
Retail credit quality is dependent on the economy and the ability of customers to manage through unfavorable economic cycles and other market changes. If the business environment were to be negatively affected by changes in economic or other market conditions, FirstEnergy's retail credit risk may be adversely impacted.
REGULATORY MATTERS
Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent amounts that are expected to be credited to customers through future regulated rates or amounts collected from customers for costs not yet incurred. FirstEnergy and the Utilities net their regulatory assets and liabilities based on federal and state jurisdictions.


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Net regulatory assets on FirstEnergy's and the Utility Registrants' Consolidated Balance Sheets are comprised of the following:
Regulatory Assets FirstEnergy OE CEI TE JCP&L Met-Ed Penelec
  (In millions)
December 31, 2011              
Regulatory transition costs $608
 $—
 $—
 $—
 $424
 $105
 $79
Customer receivables for future income taxes 508
 42
 1
 2
 29
 129
 145
Nuclear decommissioning, decontamination and spent fuel disposal costs (210) —
 —
 —
 (44) (99) (67)
Asset removal costs (240) (34) (60) (23) (147) —
 —
PJM transmission costs 340
 (3) (3) (1) —
 181
 63
Deferred generation costs 382
 125
 224
 37
 —
 (23) (11)
Distribution costs 267
 146
 73
 48
 —
 —
 —
Other 375
 87
 60
 7
 146
 36
 —
Total $2,030
 $363
 $295
 $70
 $408
 $329
 $209
December 31, 2010              
Regulatory transition costs $770
 $—
 $—
 $—
 $591
 $131
 $43
Customer receivables for future income taxes 328
 52
 2
 1
 30
 113
 130
Nuclear decommissioning, decontamination and spent fuel disposal costs (184) —
 —
 —
 (31) (92) (61)
Asset removal costs (237) (24) (47) (19) (147) —
 —
PJM transmission costs 183
 —
 —
 —
 —
 131
 52
Deferred generation costs 386
 125
 226
 35
 —
 —
 —
Distribution costs 426
 216
 155
 55
 —
 —
 —
Other 158
 34
 34
 1
 71
 13
 (1)
Total $1,830
 $403
 $370
 $73
 $514
 $296
 $163

Additionally, FirstEnergy had $381 million of net regulatory liabilities as of December 31, 2011, including $366 million of net regulatory liabilities attributable to Allegheny that are primarily related to asset removal costs. Net regulatory liabilities are classified within Other Noncurrent Liabilities on the Consolidated Balance Sheets.
Regulatory assets that do not earn a current return as of December 31, 2011 totaled approximately $413 million. Regulatory assets that do not earn a return are primarily comprised of certain regulatory transition and PJM transmission costs for Met-Ed and Penelec of $182 million and $115 million, respectively, that are expected to be recovered by 2020, and certain storm damage costs and pension and OPEB costs incurred by JCP&L of $122 million that are expected to be recovered by 2026.

RELIABILITY MATTERS

Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES, AE Supply, FGCO, FENOC, ATSI and TrAIL. The NERC is the ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including RFC. All of FirstEnergy's facilities are located within the RFC region. FirstEnergy actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by the RFC.

FirstEnergy believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such items are found, FirstEnergy develops information about the item and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an item to RFC. Moreover, it is clear that the NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with future new or amended standards cannot be determined at this time; however, 2005 amendments to the FPA provide that all prudent costs incurred to comply with the future reliability standards be recovered in rates. 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 that could have a material adverse effect on its financial condition, results of operations and cash flows.

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 resulting in customers losing power for up to eleven


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hours. 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. NERC has submitted first and second Requests for Information regarding this and another related matter. JCP&L is complying with these requests. JCP&L is not able to predict what actions, if any, the NERC may take with respect to this matter.

On August 23, 2010, FirstEnergy self-reported to RFC a vegetation encroachment event on a Met-Ed230kV line. This event did not result in a fault, outage, operation of protective equipment, or any other meaningful electric effect on any FirstEnergy transmission facilities or systems. On August 25, 2010, RFC issued a notice of enforcement to investigate the incident. FirstEnergy submitted a data response to RFC on September 27, 2010. On July 8, 2011, RFC and Met-Ed signed a settlement agreement to resolve all outstanding issues related to the vegetation encroachment event. The settlement calls for Met-Ed to pay a penalty of$650,000, and for FirstEnergy to perform certain mitigating actions. These mitigating actions include inspecting FirstEnergy's transmission system using LiDAR technology, and reporting the results of inspections, and any follow-up work, to RFC. FirstEnergy was performing the LiDAR work in response to certain other industry directives issued by NERC in 2010. NERC subsequently approved the settlement agreement and, on September 30, 2011, submitted the approved settlement to FERC for final approval. FERC approved the settlement agreement on October 28, 2011. Met-Ed subsequently paid the$650,000penalty and, on December 31, 2011, RFC sent written notice that this matter has been closed.

In 2011, RFC performed routine compliance audits of parts of FirstEnergy's bulk-power system and generally found the audited systems and process to be in full compliance with all audited reliability standards. RFC will perform additional audits in 2012.

MARYLAND
By statute enacted in 2007, the obligation of Maryland utilities to provide SOS to residential and small commercial customers, in exchange for recovery of their costs plus a reasonable profit, was extended indefinitely. The legislation also established a5-year cycle (to begin in 2008) for the MDPSC to report to the legislature on the status of SOS. PE now conducts rolling auctions to procure the power supply necessary to serve its customer load pursuant to a plan approved by the MDPSC. However, the terms on which PE will provide SOS to residential customers after the current settlement expires at the end of 2012 will depend on developments with respect to SOS in Maryland over the coming year, including but not limited to, possible MDPSC decisions in the proceedings discussed below.

The MDPSC opened a new docket in August 2007 to consider matters relating to possible “managed portfolio” approaches to SOS and other matters. “Phase II” of the case addressed utility purchases or construction of generation, bidding for procurement of demand response resources and possible alternatives if the TrAIL and PATH projects were delayed or defeated. It is unclear when the MDPSC will issue its findings in this proceeding.
In September 2009, the MDPSC opened a new proceeding to receive and consider proposals for construction of new generation resources in Maryland. In December 2009, Governor Martin O'Malley filed a letter in this proceeding in which he characterized the electricity market in Maryland as a “failure” and urged the MDPSC to use its existing authority to order the construction of new generation in Maryland, vary the means used by utilities to procure generation and include more renewables in the generation mix. In December 2010, the MDPSC issued an order soliciting comments on a model RFP for solicitation of long-term energy commitments by Maryland electric utilities. PE and numerous other parties filed comments, and on September 29, 2011, the MDPSC issued an order requiring the utilities to issue the RFP crafted by the MDPSC by October 7, 2011. The RFPs were issued by the utilities as ordered by the MDPSC. The order, as amended, indicated that bids were due by January 20, 2012, and that the MDPSC would be the entity evaluating all bids. The Chairman of the MDPSC has stated publicly that several bids were received, but no other information was released. After receipt of further comments from interested parties, including PE, on January 13, 2012, a hearing on whether more generation is needed, irrespective of what bids may have been received, was held on January 31, 2012. There has been no further action on this matter.

In September 2007, the MDPSC issued an order that required the Maryland utilities to file detailed plans for how they will meet the “EmPOWER Maryland” proposal that electric consumption be reduced by10%and electricity demand be reduced by15%, in each case by 2015.

The Maryland legislature in 2008 adopted a statute codifying the EmPOWER Maryland goals. In 2008, PE filed its comprehensive plans for attempting to achieve those goals, asking the MDPSC to approve programs for residential, commercial, industrial, and governmental customers, as well as a customer education program. The MDPSC ultimately approved the programs in August 2009 after certain modifications had been made as required by the MDPSC, and approved cost recovery for the programs in October 2009. Expenditures were estimated to be approximately$101 millionfor the PE programs for the period of 2009 to 2015 and would be recovered over thatsixyear period. Meanwhile, after extensive meetings with the MDPSC Staff and other stakeholders, PE's plans for additional and improved programs for the period 2012-2014 were filed on August 31, 2011. The MDPSC held hearings on PE's and the other utilities' plans in October 2011, and on December 22, 2011, issued an order approving Potomac Edison's plan with various modifications and follow-up assignments. On January 23, 2012, PE filed a Request for Rehearing because additional facts not considered by the MDPSC demonstrate, among other things, that conservation voltage reduction program expenditures should be accorded cost recovery through the EmPOWER surcharge, as has been provided for all other EmPOWER programs as opposed to recovery of those expenditures being addressed in a future base rate case as the MDPSC found in its order.


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In March 2009, the MDPSC issued an order temporarily suspending the right of all electric and gas utilities in the state to terminate service to residential customers for non-payment of bills. The MDPSC subsequently issued an order making various rule changes relating to terminations, payment plans, and customer deposits that make it more difficult for Maryland utilities to collect deposits or to terminate service for non-payment. The MDPSC is continuing to collect data on payment plan and related issues and has adopted regulations that expand the summer and winter “severe weather” termination moratoria when temperatures are very high or very low, fromoneday, as provided by statute, tothreedays on each occurrence.
The Maryland legislature passed a bill on April 11, 2011, which requires the MDPSC to promulgate rules by July 1, 2012 that address service interruptions, downed wire response, customer communication, vegetation management, equipment inspection, and annual reporting. In crafting the regulations, the legislation directs the MDPSC to consider cost-effectiveness, and provides that the MDPSC may adopt different standards for different utilities based on such factors as system design and existing infrastructure, geography, and customer density. Beginning in July 2013, the MDPSC is required to assess each utility's compliance with the new rules, and may assess penalties of up to$25,000per day per violation. The MDPSC convened a working group of utilities, regulators, and other interested stakeholders to address the topics of the proposed rules. A draft of the rules was filed, along with the report of the working group, on October 27, 2011. Hearings to consider the rules and comments occurred over four days between December 8 and 15, 2011, after which revised rules were sent for legislative review. The proposed rules were published in the Maryland Register on February 24, 2012, and a deadline of March 26, 2012, was set for the filing of further comments. A further hearing is required before the rules could become final. Separately, on July 7, 2011, the MDPSC adopted draft rules requiring monitoring and inspections for contact voltage. The draft rules were published in September, 2011. After a further hearing in October, 2011, the final rules were re-published and became effective on November 28, 2011.

NEW JERSEY

On September 8, 2011, the Division of Rate Counsel filed a Petition with the NJBPU asserting that it has reason to believe that JCP&L is earning an unreasonable return on its New Jersey jurisdictional rate base. The Division of Rate Counsel requests that the NJBPU order JCP&L to file a base rate case petition so that the NJBPU may determine whether JCP&L's current rates for electric service are just and reasonable. JCP&L filed an answer to the Petition on September 28, 2011, stating, inter alia, that the Division of Rate Counsel analysis upon which it premises its Petition contains errors and inaccuracies, that JCP&L's achieved return on equity is currently within a reasonable range, and that there is no reason for the NJBPU to require JCP&L to file a base rate case at this time.On November 30, 2011, the NJBPU ordered that the matter be assigned to the NJBPU President to act as presiding officer to set and modify the schedule for this matter as appropriate, decide upon motions, and otherwise control the conduct of this case, without the need for full Board approval. The matter is pending and a schedule for further proceedings has not yet been established.

On September 22, 2011, the NJBPU ordered that JCP&L hire a Special Reliability Master, subject to NJBPU approval, to evaluate JCP&L's design, operating, maintenance and performance standards as they pertain to the Morristown, New Jersey underground electric distribution system, and make recommendations to JCP&L and the NJBPU on the appropriate courses of action necessary to ensure adequate reliability and safety in the Morristown underground network.On October 12, 2011, the Special Reliability Master was selected and on January 31, 2012, the project report was submitted to the Company and NJBPU Staff. On February 10, 2012, the NJBPU accepted the report and directed the Staff to present recommendations on March 12, 2012, on actions required by JCP&L to ensure the safe, reliable operation of the Morristown network.

Pursuant to a formal Notice issued by the NJBPU on September 14, 2011, public hearings were held on September 26 and 27, 2011, to solicit public comments regarding the state of preparedness and responsiveness of the local electric distribution companies prior to, during and after Hurricane Irene. By subsequent Notice issued September 28, 2011, additional hearings were held in October 2011. Additionally, the NJBPU accepted written comments through October 31, 2011 related to this inquiry.On December 4, 2011, the NJBPU Division of Reliability and Security issued a Request for Qualifications soliciting bid proposals from qualified consulting firms to provide expertise in the review and evaluation of New Jersey's electric distribution companies' preparation and restoration to Hurricane Irene and the October 2011 snowstorm. Responsive bids were submitted on January 20, 2012, and the report of selected bidder is to be submitted to the NJPBU 120 days from the date the contract is awarded. On December 14, 2011, the NJBPU Staff filed a report of its preliminary findings and recommendations with respect to the electric utility companies' planning and response to Hurricane Irene and the October 2011 snowstorm. The NJBPU has not indicated what additional action, if any, may be taken as a result of information obtained through this process.

OHIO

The Ohio Companies operate under an ESP, which expires on May 31, 2014. The material terms of the ESP include: generation supplied through a CBP commencing June 1, 2011; a load cap of no less than80%, which also applies to tranches assigned post-auction; a6%generation discount to certain low income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (FES is one of the wholesale suppliers to the Ohio Companies); no increase in base distribution rates through May 31, 2014; and a new distribution rider, Rider DCR, to recover a return of, and on, capital investments in the delivery system. The Ohio Companies also agreed not to recover from retail customers certain costs related to transmission cost allocations by PJM as a result of ATSI's integration into PJM for the longer of the five-year period from June 1, 2011 through May 31, 2015 or when the amount of costs avoided by customers for certain types of products totals$360 milliondependent on the outcome of certain PJM proceedings, agreed to establish a$12 millionfund to assist low income customers over the term of the ESP and agreed to


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additional matters related to energy efficiency and alternative energy requirements.

Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total annual energy savings equivalent to approximately166,000MWH in 2009,290,000MWH in 2010,410,000MWH in 2011,470,000MWH in 2012 and530,000MWH in 2013, with additional savings required through 2025. Utilities were also required to reduce peak demand in 2009 by1%, with an additional0.75%reduction each year thereafter through 2018.

In December 2009, the Ohio Companies filed the requiredthreeyear 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. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers in 2012. The PUCO issued an Opinion and Order generally approving the Ohio Companies'three-year plan, and the Ohio Companies are in the process of implementing those programs included in the Plan. OE fell short of its statutory 2010 energy efficiency and peak demand reduction benchmarks and therefore, on January 11, 2011, it requested that its 2010 energy efficiency and peak demand reduction benchmarks be amended to actual levels achieved in 2010. Moreover, because the PUCO indicated, when approving the 2009 benchmark request, that it would modify the Ohio Companies' 2010 (and 2011 and 2012) energy efficiency benchmarks when addressing the portfolio plan, the Ohio Companies were not certain of their 2010 energy efficiency obligations. Therefore, CEI and TE (each of which achieved its 2010 energy efficiency and peak demand reduction statutory benchmarks) also requested an amendment if and only to the degree one was deemed necessary to bring them into compliance with their yet-to-be-defined modified benchmarks. On May 19, 2011, the PUCO granted the request to reduce the 2010 energy efficiency and peak demand reductions to the level achieved in 2010 for OE, while finding that the motion was moot for CEI and TE. On June 2, 2011, the Ohio Companies filed an application for rehearing to clarify the decision related to CEI and TE. On July 27, 2011, the PUCO denied that application for rehearing, but clarified that CEI and TE could apply for an amendment in the future for the 2010 benchmarks should it be necessary to do so. Failure to comply with the benchmarks or to obtain such an amendment may subject the Ohio Companies to an assessment of a penalty by the PUCO. In addition to approving the programs included in the plan, with only minor modifications, the PUCO authorized the Ohio Companies to recover all costs related to the original CFL program that the Ohio Companies had previously suspended at the request of the PUCO. Applications for Rehearing were filed by the Ohio Companies, Ohio Energy Group and Nucor Steel Marion, Inc. on April 22, 2011, regarding portions of the PUCO's decision, including the method for calculating savings and certain changes made by the PUCO to specific programs. On September 7, 2011, the PUCO denied those applications for rehearing. The PUCO also included a new standard for compliance with the statutory energy efficiency benchmarks by requiring electric distribution companies to offer “all available cost effective energy efficiency opportunities” regardless of their level of compliance with the benchmarks as set forth in the statute.On October 7, 2011, the Ohio Companies, the Industrial Energy Users - Ohio, and the Ohio Energy Group filed applications for rehearing, arguing that the PUCO'S new standard is unlawful. The Ohio Companies also asked the PUCO to withdraw its amendment of CEI's and TE's 2010 energy efficiency benchmarks. The PUCO did not rule on the Applications for Rehearing within thirty days, thus denying them by operation of law. On December 30, 2011, the Ohio Companies filed a notice of appeal with the Supreme Court of Ohio, challenging the PUCO's new standard. No procedural schedule has been established.

Additionally, under SB221, electric utilities and electric service companies are required to serve part of their load in 2011 from renewable energy resources equivalent to1.00%of the average of the KWH they served in 2008-2010; in 2012 from renewable energy resources equivalent to1.50%of the average of the KWH they served in 2009-2011; and in 2013 from renewable energy resources equivalent to2.00%of the average of the KWH they served in 2010-2012. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RECs acquired through thesetwoRFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. In March 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market and reduced the Ohio Companies' aggregate 2009 benchmark to the level of SRECs the Ohio Companies acquired through their 2009 RFP processes, provided the Ohio Companies' 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC benchmark. On April 15, 2011, the Ohio Companies filed an application seeking an amendment to each of their 2010 alternative energy requirements for solar RECs generated in Ohio on the basis that an insufficient quantity of solar resources are available in the market but reflecting solar RECs that they have obtained and providing additional information regarding efforts to secure solar RECs. On August 3, 2011, the PUCO granted the Ohio Companies' force majeure request for 2010 and increased their 2011 benchmark by the amount of SRECs generated in Ohio that the Ohio Companies were short in 2010. On September 2, 2011, the Environmental Law and Policy Center and Nucor Steel Marion, Inc. filed applications for rehearing. The Ohio Companies filed their response on September 12, 2011. These applications for rehearing were denied by the PUCO on September 20, 2011, but as part of its Entry on Rehearing the PUCO opened a new docket to review the Ohio Companies' alternative energy recovery rider. Separately,oneparty has filed a request that the PUCO audit the cost of the Ohio Companies' compliance with the alternative energy requirements and the Ohio Companies' compliance with Ohio law. The PUCO selected auditors to perform a financial and a management audit, and final audit reports are to be filed with the PUCO by May 15, 2012. In August 2011, the Ohio Companies conducted two RFP processes to obtain RECs to meet the statutory benchmarks for 2011 and beyond.

PENNSYLVANIA
The PPUC entered an Order on March 3, 2010 that denied the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, directed Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructed Met-Ed and Penelec to work with the various intervening parties to file a recommendation to the PPUC regarding the establishment of a separate account for all marginal transmission losses


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collected from customers plus interest to be used to mitigate future generation rate increases beginning January 1, 2011. In March 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 to end collection of costs for marginal transmission losses. The PPUC granted the requested stay until December 31, 2010. Pursuant to the PPUC's order, Met-Ed and Penelec filed plans to establish separate accounts for marginal transmission loss revenues and related interest and carrying charges. Pursuant to the plan approved by the PPUC, Met-Ed and Penelec began to refund those amounts to customers in January 2011, and the refunds are continuing over a 29 month period until the full amounts previously recovered for marginal transmission loses are refunded. In April 2010, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania appealing the PPUC's March 3, 2010 Order. On June 14, 2011, the Commonwealth Court issued an opinion and order affirming the PPUC's Order to the extent that it holds that line loss costs are not transmission costs and, therefore, the approximately$254 millionin marginal transmission losses and associated carrying charges for the period prior to January 1, 2011, are not recoverable under Met-Ed's and Penelec's TSC riders. Met-Ed and Penelec filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court and also a complaint seeking relief in the U.S. District Court for the Eastern District of Pennsylvania, which was subsequently amended. The PPUC filed a Motion to Dismiss Met-Ed's and Penelec's Amended Complaint on September 15, 2011. Met-Ed and Penelec filed a Responsive brief in Opposition to the PPUC's Motion to Dismiss on October 11, 2011. Although the ultimate outcome of this matter cannot be determined at this time, Met-Ed and Penelec believe that they should ultimately prevail through the judicial process and therefore expect to fully recover the approximately$254 million($189 millionfor Met-Ed and$65 millionfor Penelec) in marginal transmission losses for the period prior to January 1, 2011.

In each of May 2008, 2009 and 2010, the PPUC approved Met-Ed's and Penelec's annual updates to their TSC rider for the annual periods between June 1, 2008 to 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 PPUC's approval in May 2010 authorized an increase to the TSC for Met-Ed's customers to provide for full recovery by December 31, 2010.

In February 2010, Penn filed a Petition for Approval of its DSP for the period June 1, 2011 through May 31, 2013. In July 2010, the parties to the proceeding filed a Joint Petition for Settlement of all issues. Although the PPUC's Order approving the Joint Petition held that the provisions relating to the recovery of MISO exit fees and one-time PJM integration costs (resulting from Penn's June 1, 2011 exit from MISO and integration into PJM) were approved, it made such provisions subject to the approval of cost recovery by FERC. Therefore, Penn may not put these provisions into effect until FERC has approved the recovery and allocation of MISO exit fees and PJM integration costs.

Pennsylvania adopted Act 129 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, (EE&C Plan), by July 1, 2009, setting forth the utilities' plans to reduce energy consumption by a minimum of1%and3%by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of4.5%by May 31, 2013. Act 129 provides for potentially significant financial penalties to be assessed upon utilities that fail to achieve the required reductions in consumption and peak demand. Act 129 also required utilities to file a SMIP with the PPUC.

The PPUC entered an Order in February 2010 giving final approval to all aspects of the EE&C Plans of Met-Ed, Penelec and Penn and the tariff rider became effective March 1, 2010. On February 18, 2011, the companies filed a petition to approve their First Amended EE&C Plans. On June 28, 2011, a hearing on the petition was held before an ALJ.On December 15, 2011, the ALJ recommended that the amended plans be approved as proposed, and on January 12, 2012, the Commission approved the plans.
WP filed its original EE&C Plan in June 2009, which the PPUC approved, in large part, by Opinion and Order entered in October 2009. In September 2010, WP filed an amended EE&C Plan that is less reliant on smart meter deployment, which the PPUC approved in January 2011.
On August 9, 2011, WP filed a petition to approve its Second Amended EE&C Plan. The proposed Second Revised Plan includes measures and a new program and implementation strategies consistent with the successful EE&C programs of Met-Ed, Penelec and Penn that are designed to enable WP to achieve the post-2011 Act 129 EE&C requirements.On January 6, 2012, a Joint Petition for Settlement of all issues was filed by the parties to the proceeding.

The Pennsylvania Companies submitted a preliminary report on July 15, 2011, and a final report on November 15, 2011, in which they reported on their compliance with statutory May 31, 2011, energy efficiency benchmarks.Met-Ed, Penelec and Penn achieved the 2011 benchmarks; however WP has been unable to provide final results because several customers are still accumulating necessary documentation for projects that may qualify for inclusion in the final results. Preliminary numbers indicate that WP did not achieve its 2011 benchmark and it is not known at this time whether WP will be subject to a fine for failure to achieve the benchmark. WP is unable to predict the outcome of this matter or estimate any possible loss or range of loss.

In December 2009, WP filed a motion to reopen the evidentiary record to submit an alternative smart meter plan proposing, among other things, a less-rapid deployment of smart meters.

In light of the significant expenditures that would be associated with its smart meter deployment plans and related infrastructure upgrades, as well as its evaluation of recent PPUC decisions approving less-rapid deployment proposals by other utilities, WP re-


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evaluated its Act 129 compliance strategy, including both its plans with respect to smart meter deployment and certain smart meter dependent aspects of the EE&C Plan. In October 2010, WP and Pennsylvania's OCA filed a Joint Petition for Settlement addressing WP's smart meter implementation plan with the PPUC. Under the terms of the proposed settlement, WP proposed to decelerate its previously contemplated smart meter deployment schedule and to target the installation of approximately25,000smart meters in support of its EE&C Plan, based on customer requests, by mid-2012. The proposed settlement also contemplates that WP take advantage of the30-month grace period authorized by the PPUC to continue WP's efforts to re-evaluate full-scale smart meter deployment plans. WP currently anticipates filing its plan for full-scale deployment of smart meters in June 2012. Under the terms of the proposed settlement, WP would be permitted to recover certain previously incurred and anticipated smart-meter related expenditures through a levelized customer surcharge, with certain expenditures amortized over a ten-year period. Additionally, WP would be permitted to seek recovery of certain other costs as part of its revised SMIP that it currently intends to file in June 2012, or in a future base distribution rate case.
Following additional proceedings, on March 9, 2011, WP submitted an Amended Joint Petition for Settlement which restates the Joint Petition for Settlement filed in October 2010, adds the PPUC's Office of Trial Staff as a signatory party, and confirms the support or non-opposition of all parties to the settlement.Oneparty retained the ability to challenge the recovery of amounts spent on WP's original smart meter implementation plan. A Joint Stipulation with the OSBA was also filed on March 9, 2011. The PPUC approved the Amended Joint Petition for Full Settlement by order entered June 30, 2011.

By Tentative Order entered in September 2009, the PPUC provided for an additional30-day comment period on whether the 1998 Restructuring Settlement, which addressed how Met-Ed and Penelec were going to implement direct access to a competitive market for the generation of electricity, allows Met-Ed and Penelec to apply over-collection of NUG costs for select and isolated months to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists. In response to the Tentative Order, various parties filed comments objecting to the accounting method utilized by Met-Ed and Penelec.On January 30, 2012, the Commission entered a final order approving Met-Ed's and Penelec's accounting methodology whereby NUG over-collection revenue may be used to reduce non-NUG stranded costs, even if a cumulative NUG stranded cost balance exists.

In the PPUC Order approving the FirstEnergy and Allegheny merger, the PPUC announced that a separate statewide investigation into Pennsylvania's retail electricity market will be conducted with the goal of making recommendations for improvements to ensure that a properly functioning and workable competitive retail electricity market exists in the state. On April 29, 2011, the PPUC entered an Order initiating the investigation and requesting comments from interested parties on eleven directed questions concerning retail markets in Pennsylvania. Met-Ed, Penelec, Penn Power and WP submitted joint comments on June 3, 2011. FES also submitted comments on June 3, 2011. On June 8, 2011, the PPUC conducted an en banc hearing on these issues at which both the Pennsylvania Companies and FES participated and offered testimony.A technical conference was held on August 10, 2011, and a second en banc was held on November 10, 2011, to discuss intermediate steps that can be taken to promote the development of a competitive market. Teleconferences are scheduled through March 2012, with another en banc hearing to be held on March 21, 2012, to explore the future of default service in Pennsylvania following the expiration of the upcoming default service plans on May 31, 2015. Following the issuance of a Tentative Order and comments filed by numerous parties, the Commission entered a final order on December 16, 2011, providing recommendations for components to be included in upcoming default service plans. An intermediate work plan was also presented on December 16, 2011, by Tentative Order, on which initial comments were submitted by Met-Ed, Penelec, Penn and WP on January 17, 2012. FES also submitted comments. Reply comments were submitted on February 1, 2012. It is expected that a final order implementing the intermediate work plan and a long range plan will be presented by the PPUC, both in March 2012.

The PPUC issued a Proposed Rulemaking Order on August 25, 2011, which proposed a number of substantial modifications to the current Code of Conduct regulations that were promulgated to provide competitive safeguards to the competitive retail electric market in Pennsylvania. The proposed changes include, but are not limited to: an EGS may not have the same or substantially similar name as the EDC or its corporate parent; EDCs and EGSs would not be permitted to share office space and would need to occupy different buildings; EDCs and affiliated EGSs could not share employees or services, except certain corporate support, emergency, or tariff services (the definition of "corporate support services" excludes items such as information systems, electronic data interchange, strategic management and planning, regulatory services, legal services, or commodities that have been included in regulated rates at less than market value); and an EGS must enter into a trademark agreement with the EDC before using its trademark or service mark. The Proposed Rulemaking Order, which was published on February 11, 2012, calls for comments to be submitted by March 27, 2012. If implemented these rules could require a significant change in the way FES, Met-Ed, Penelec, Penn and WP do business in Pennsylvania, and could possibly have an adverse impact on their results of operations and financial condition.

In November 2011, Met-Ed, Penelec, Penn and WP filed a Joint Petition for Approval of their Default Service Plan for the period June 1, 2013 through May 31, 2015. The Pennsylvania Companies' direct case was submitted in its entirety on December 20, 2011. Evidentiary hearings are scheduled for April 11-13, 2012, and a final order must be entered by the PPUC by August 17, 2012.

WEST VIRGINIA
In 2009, the West Virginia Legislature enacted the AREPA, which generally requires that a specified minimum percentage of electricity sold to retail customers in West Virginia by electric utilities each year be derived from alternative and renewable energy resources according to a predetermined schedule of increasing percentage targets, including10%by 2015,15%by 2020, and25%by 2025.


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In November 2010, the WVPSC issued RPS Rules, which became effective on January 4, 2011. Under the RPS Rules, on or before January 1, 2011, each electric utility subject to the provisions of this rule was required to prepare an alternative and renewable energy portfolio standard compliance plan and file an application with the WVPSC seeking approval of such plan. MP and PE filed their combined compliance plan in December 2010. A hearing was held at the WVPSC on June 13, 2011. An order was issued by the WVPSC in September 2011, which conditionally approved MP's and PE's compliance plan, contingent on the outcome of the resource credits case discussed below.

Additionally, in January 2011, MP and PE filed an application with the WVPSC seeking to certify three facilities as Qualified Energy Resource Facilities. The application was approved and the three facilities are capable of generating renewable credits which will assist the companies in meeting their combined requirements under the AREPA. An annual update filing is due on March 31, 2012. Further, in February 2011, MP and PE filed a petition with the WVPSC seeking an Order declaring that MP is entitled to all alternative and renewable energy resource credits associated with the electric energy, or energy and capacity, that MP is required to purchase pursuant to electric energy purchase agreements between MP and three non-utility electric generating facilities in West Virginia. The City of New Martinsville and Morgantown Energy Associates, each the owner of one of the contracted resources, has participated in the case in opposition to the Petition. A hearing was held at the WVPSC on August 25 and 26, 2011.On November 22, 2011, the WVPSC issued an order granting ownership of all RECs produced by the facilities to MP. On December 22, 2011, the WVPSC order was appealed, and the order was stayed pending the outcome of the appeal. MP's brief was filed on February 13, 2012. Should MP be unsuccessful in the appeal, it will have to procure the requisite RECs to comply with AREPA from other sources. MP expects to recover such costs from customers.

In September 2011, MP and PE filed with the WVPSC to recover costs associated with fuel and purchased power (the ENEC) in the amount of$32 millionwhich represents an approximate3%overall increase in such costs over the past two years, primarily attributable to rising coal prices. The requested increase was partially offset by$2.5 millionof synergy savings directly resulting from the merger of FirstEnergy and AE, which closed in February 2011. Under a cost recovery clause established by the WVPSC in 2007, MP and PE customer bills are adjusted periodically to reflect upward or downward changes in the cost of fuel and purchased power. The utilities' most recent request to recover costs for fuel and purchased power was in September 2009.MP and PE entered into a Settlement Agreement related to this matter. The WVPSC issued an order on December 30, 2011, approving the settlement agreement. The approved settlement resulted in an increase of$19.6 million, instead of the requested$32 million, with additional costs to be recovered over time with a carrying charge.

FERC MATTERS

PJM Transmission Rate

In April 2007, FERC issued 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, FERC directed that costs for new transmission facilities that are rated at500kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate based on the amount of load served in a transmission zone. Costs for new transmission facilities that are rated at less than500kV, however, are to be allocated on a load flow methodology, which is generally referred to as a “beneficiary pays” approach to allocating the cost of high voltage transmission facilities.

FERC's Opinion 494 order was appealed to the U.S. Court of Appeals for the Seventh Circuit, which issued a decision in August 2009. The court affirmed FERC's ratemaking treatment for existing transmission facilities, but found that FERC had not supported its decision to allocate costs for new500kV and higher voltage facilities on a load ratio share basis and, based on this finding, remanded the rate design issue to FERC.

In an order dated January 21, 2010, FERC set the matter for a “paper hearing” and requested parties to submit written comments pursuant to the schedule described in the order. FERC identifiednineseparate issues for comments and directed PJM to file the first round of comments on February 22, 2010, with other parties submitting responsive comments and then reply comments on later dates. PJM filed certain studies with FERC on April 13, 2010, in response to the FERC order. PJM's filing demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain load serving entities in PJM bearing the majority of the 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. Other utilities and state commissions supported continued socialization of these costs on a load ratio share basis. This matter is awaiting action by FERC. FirstEnergy cannot predict the outcome of this matter or estimate the possible loss or range of loss.

RTO Realignment

On June 1, 2011, ATSI and the ATSI zone entered into PJM. The move was performed as planned with no known operational or reliability issues for ATSI or for the wholesale transmission customers in the ATSI zone.

On February 1, 2011, ATSI in conjunction with PJM filed its proposal with FERC for moving its transmission rate into PJM's tariffs. On April 1, 2011, the MISO TOs (including ATSI) filed proposed tariff language that describes the mechanics of collecting and


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administering MTEP costs from ATSI-zone ratepayers. From March 20, 2011 through April 1, 2011, FirstEnergy, PJM and the MISO submitted numerous filings for the purpose of effecting movement of the ATSI zone to PJM on June 1, 2011. These filings include amendments to the MISO's tariffs (to remove the ATSI zone), submission of load and generation interconnection agreements to reflect the move into PJM, and submission of changes to PJM's tariffs to support the move into PJM.

On May 31, 2011, FERC issued orders that address the proposed ATSI transmission rate, and certain parts of the MISO tariffs that reflect the mechanics of transmission cost allocation and collection. In its May 31, 2011 orders, FERC approved ATSI's proposal to move the ATSI formula rate into the PJM tariff without significant change. Speaking to ATSI's proposed treatment of the MISO's exit fees and charges for transmission costs that were allocated to the ATSI zone, FERC required ATSI to present a cost-benefit study that demonstrates that the benefits of the move for transmission customers exceed the costs of any such move, which FERC had not previously required. Accordingly, FERC ruled that these costs must be removed from ATSI's proposed transmission rates until such time as ATSI files and FERC approves the cost-benefit study. On June 30, 2011, ATSI submitted the compliance filing that removed the MISO exit fees and transmission cost allocation charges from ATSI's proposed transmission rates. Also on June 30, 2011, ATSI requested rehearing of FERC's decision to require a cost-benefit analysis as part of FERC's evaluation of ATSI's proposed transmission rates. Finally, and also on June 30, 2011, the MISO and the MISO TOs filed a competing compliance filing - one that would require ATSI to pay certain charges related to construction and operation of transmission projects within the MISO even though FERC ruled that ATSI cannot pass these costs on to ATSI's customers. ATSI on the one hand, and the MISO and MISO TOs on the other, have submitted subsequent filings - each of which is intended to refute the other's claims. ATSI's compliance filing and request for rehearing, as well as the pleadings that reflect the dispute between ATSI and the MISO/MISO TOs, are currently pending before FERC.

From late April 2011 through June 2011, FERC issued other orders that address ATSI's move into PJM. Also, ATSI and the MISO were able to negotiate an agreement of ATSI's responsibility for certain charges associated with long term firm transmission rights that, according to the MISO, were payable by the ATSI zone upon its departure from the MISO. ATSI did not and does not agree that these costs should be charged to ATSI but, in order to settle the case and all claims associated with the case, ATSI agreed to a one-time payment of$1.8 millionto the MISO. This settlement agreement has been submitted for FERC's review and approval. The final outcome of those proceedings that address the remaining open issues related to ATSI's move into PJM and their impact, if any, on FirstEnergy cannot be predicted at this time.

MISO Multi-Value Project Rule Proposal

In July 2010, MISO and certain MISO transmission owners jointly filed with FERC their proposed cost allocation methodology for certain new transmission projects. The new transmission projects--described as MVPs - are a class of transmission projects that are approved via the MTEP. The filing parties proposed to allocate the costs of MVPs by means of a usage-based charge that will be applied to all loads within the MISO footprint, and to energy transactions that call for power to be “wheeled through” the MISO as well as to energy transactions that “source” in the MISO but “sink” outside of MISO. The filing parties expect that the MVP proposal will fund the costs of large transmission projects designed to bring wind generation from the upper Midwest to load centers in the east. The filing parties requested an effective date for the proposal of July 16, 2011. On August 19, 2010, MISO's Board approved the first MVP project -- the “Michigan Thumb Project.” Under MISO's proposal, the costs of MVP projects approved by MISO's Board prior to the June 1, 2011 effective date of FirstEnergy's integration into PJM would continue to be allocated to FirstEnergy. MISO estimated that approximately$15 millionin annual revenue requirements would be allocated to the ATSI zone associated with the Michigan Thumb Project upon its completion.

In September 2010, FirstEnergy filed a protest to the MVP proposal arguing that MISO's proposal to allocate costs of MVPs projects across the entire MISO footprint does not align with the established rule that cost allocation is to be based on cost causation (the “beneficiary pays” approach). FirstEnergy also argued that, in light of progress that had been made to date in the ATSI integration into PJM, it would be unjust and unreasonable to allocate any MVP costs to the ATSI zone, or to ATSI. Numerous other parties filed pleadings on MISO's MVP proposal.

In December 2010, FERC issued an order approving the MVP proposal without significant change. Despite being presented with the issue by FirstEnergy and the MISO, the FERC did not address clearly the question of whether the MVP costs would be payable by ATSI or load in the ATSI zone. FERC stated that the MISO's tariffs obligate ATSI to pay all charges that attached prior to ATSI's exit but ruled that the question of the amount of costs that are to be allocated to ATSI or to load in the ATSI zone were beyond the scope of FERC's order and would be addressed in future proceedings.

On January 18, 2011, FirstEnergy requested rehearing of FERC's order. In its rehearing request, FirstEnergy argued that because the MVP rate is usage-based, costs could not be applied to ATSI, which is a stand-alone transmission company that does not use the transmission system. FirstEnergy also renewed its arguments regarding cost causation and the impropriety of allocating costs to the ATSI zone or to ATSI.On October 21, 2011, FERC issued its order on rehearing, but that order did not address FirstEnergy's argument directly. FERC ruled instead that if ATSI was subject to MVP charges then ATSI owed these charges upon exit of the MISO. On October 31, 2011, FESC filed a Petition of Review for the FERC's December 2010 order and October 21, 2011 order on rehearing of that order with the U.S. Court of Appeals for the D.C. Circuit. Other parties also filed appeals of those orders and, in November, 2011, the cases were consolidated for briefing and disposition in the U.S. Court of Appeals for the Seventh Circuit. On January 27, 2012, the court ordered the FERC to file a proposed briefing format and schedule on or before March 20, 2012.



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On August 3, 2011, FirstEnergy filed a complaint with FERC based on the FERC's December 2010 order. In the complaint, FirstEnergy argued that ATSI perfected the legal and financial requirements necessary to exit MISO before any MVP responsibilities could attach and asked FERC to rule that MISO cannot charge ATSI for MVP costs. On September 2, 2011, MISO, its TOs and other parties, filed responsive pleadings. On September 19, 2011, ATSI filed an answer. On December 29, 2011, the MISO and the MISO TOs filed a new “Schedule 39” to the MISO's tariff. Schedule 39 purports to establish a process whereby the MISO would bill TOs for MVP costs that, according to the MISO, attached to the utility prior to such TOs withdrawal from the MISO. On January 19, 2012, FirstEnergy filed a protest to the MISO's new Schedule 39 tariff.

On February 27, 2012, FERC issued an order (February 2012 Order) dismissing ATSI's August 3, 2011 complaint. In the February 2012 Order, FERC accepted the MISO's Schedule 39 tariff, subject to hearings and potential refund of MVP charges to ATSI. The basis for any subsequent hearing is whether the Schedule 39 tariff was in effect at the time that ATSI exited the MISO. FirstEnergy is evaluating the February 2012 Order and will determine the next steps.

FirstEnergy cannot predict the outcome of these proceedings or estimate the possible loss or range of loss.

FirstEnergy Companies' PJM FTR Contract Underfunding Complaint

On December 28, 2011, FES and AE Supply filed a complaint with FERC against PJM challenging the ongoing underfunding of FTR contracts, which exist to hedge against transmission congestion in the day-ahead markets. The underfunding is a result of PJM's practice of using the funds that are intended to pay the holders of FTR contracts to pay instead for congestion costs that occur in the real time markets. Underfunding of the FTR contracts resulted in losses of approximately$35 millionto FES and AE Supply in the 2010-2011 Delivery Year. To date, losses for the 2011-2012 Delivery Year are estimated to be approximately$6 million.

On January 13, 2012, PJM filed comments that describe changes to the PJM tariff that, if adopted, should remedy the underfunding issue. Many parties also filed comments supporting FES' and AE Supply's position. Other parties, generally representatives of end-use customers who will have to pay the charges, filed in opposition to the complaint. The matter is currently pending before FERC. FirstEnergy cannot predict the outcome of this matter or estimate the possible loss or range of loss.

California Claims Matters

In October 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the CDWR during 2001. The settlement proposal claims that CDWR is owed approximately$190 millionfor these alleged overcharges. This proposal was made in the context of mediation efforts by FERC and the United States Court of Appeals for the Ninth Circuit in pending proceedings to resolve all outstanding refund and other claims, including claims of alleged price manipulation in the California energy markets during 2000 and 2001. The Ninth Circuit has since remandedoneof those proceedings to FERC, which arises out of claims previously filed with FERC by the California Attorney General on behalf of certain California parties against various sellers in the California wholesale power market, including AE Supply (the Lockyer case). AE Supply and several other sellers filed motions to dismiss the Lockyer case. In March 2010, the judge assigned to the case entered an opinion that granted the motions to dismiss filed by AE Supply and other sellers and dismissed the claims of the California Parties. On May 4, 2011, FERC affirmed the judge's ruling. On June 3, 2011, the California parties requested rehearing of the May 4, 2011 order. The request for rehearing remains pending.

In June 2009, the California Attorney General, on behalf of certain California parties, filed a second complaint with FERC against various sellers, including AE Supply (the Brown case), again seeking refunds for trades in the California energy markets during 2000 and 2001. The above-noted trades with CDWR are the basis for including AE Supply in this new complaint. AE Supply filed a motion to dismiss the Brown complaint that was granted by FERC on May 24, 2011. On June 23, 2011, the California Attorney General requested rehearing of the May 24, 2011 order. That request for rehearing also remains pending. FirstEnergy cannot predict the outcome of either of the above matters or estimate the possible loss or range of loss.

PATH Transmission Project

The PATH Project is comprised of a765kV transmission line that was proposed to extend from West Virginia through Virginia and into Maryland, modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland.

PJM initially authorized construction of the PATH Project in June 2007. In December 2010, PJM advised that its 2011 Load Forecast Report included load projections that are different from previous forecasts and that may have an impact on the proposed in-service date for the PATH Project. As part of its 2011 RTEP, and in response to a January 19, 2011, directive by a Virginia Hearing Examiner, PJM conducted a series of analyses using the most current economic forecasts and demand response commitments, as well as potential new generation resources. Preliminary analysis revealed the expected reliability violations that necessitated the PATH Project had moved several years into the future. Based on those results, PJM announced on February 28, 2011, that its Board of Managers had decided to hold the PATH Project in abeyance in its 2011 RTEP and directed FirstEnergy and AEP, as the sponsoring transmission owners, to suspend current development efforts on the project, subject to those activities necessary to maintain the project in its current state, while PJM conducts more rigorous analysis of the need for the project as part of its continuing RTEP


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process. PJM stated that its action did not constitute a directive to FirstEnergy and AEP to cancel or abandon the PATH Project. PJM further stated that it will complete a more rigorous analysis of the PATH Project and other transmission requirements and its Board will review this comprehensive analysis as part of its consideration of the 2011 RTEP. On February 28, 2011, affiliates of FirstEnergy and AEP filed motions or notices to withdraw applications for authorization to construct the project that were pending before state commissions in West Virginia, Virginia and Maryland. Withdrawal was deemed effective upon filing the notice with the MDPSC. The WVPSC and VSCC have granted the motions to withdraw.

PATH submitted a filing to FERC to implement a formula rate tariff effective March 1, 2008. In a November 19, 2010 order addressing various matters relating to the formula rate, FERC set the project's base ROE for hearing and reaffirmed its prior authorization of a return on CWIP, recovery of start-up costs and recovery of abandonment costs. In the order, FERC also granted a1.5%ROE incentive adder and a0.5%ROE adder for RTO participation. These adders will be applied to the base ROE determined as a result of the hearing. The PATH Companies, Joint Intervenors, Joint Consumer Advocates and FERC staff have agreed to a four year moratorium. A settlement was reached, which reflects a base ROE of10.4%(plus authorized adders) effective January 1, 2011. Accordingly, the revised ROE was reflected in a revised Projected Transmission Revenue Requirement for 2011 with true-up occurring in 2013. The FirstEnergy portion of the refund for March 1, 2008, through December 31, 2010, is approximately$2 million(inclusive of interest). The refund amount was computed using a base ROE of10.8%plus authorized adders. On October 7, 2011, PATH and six intervenors submitted to FERC an unopposed settlement agreement. Contemporaneous with this submission, PATH and the six intervenors filed with the Chief ALJ of FERC a joint motion for interim approval and authorization to implement the refund on an interim basis pending issuance of a FERC order acting on the settlement agreement. On October 12, 2011, the motion for interim approval and authorization to implement the refund was granted by the Chief ALJ. On February 16, 2012, FERC approved the settlement agreement and dismissed as moot, in light of its approval of the settlement, PATH's pending request for rehearing of the November 19, 2010 order.

Yards Creek
The Yards Creek Pumped Storage Project is a400MW hydroelectric project located in Warren County, New Jersey. JCP&L owns an undivided50%interest in the project, and operates the project. PSEG Fossil, LLC, a subsidiary of Public Service Enterprise Group, owns the remaining interest in the plant. The project was constructed in the early 1960s, and became operational in 1965. Authorization to operate the project is by a license issued by the FERC. The existing license expires on February 28, 2013.

In February 2011, JCP&L and PSEG filed a joint application with FERC to renew the license for an additional forty years. The companies are pursuing relicensure through FERC's ILP. Under the ILP, FERC will assess the license applications, issue draft and final Environmental Assessments/Environmental Impact Studies (as required by NEPA), and provide opportunities for intervention and protests by affected third parties. FERC may hold hearings during the two-year ILP licensure period. FirstEnergy expects FERC to issue the new license within the remaining portion of the two-year ILP period. To the extent, however, that the license proceedings extend beyond the February 28, 2013 expiration date for the current license, the current license will be extended yearly as necessary to permit FERC to issue the new license.
Seneca

The Seneca Pumped Storage Project is a451MW hydroelectric project located in Warren County, Pennsylvania owned and operated by FGCO. FGCO holds the current FERC license that authorizes ownership and operation of the project. The current FERC license will expire on November 30, 2015. FERC's regulations call for a five-year relicensing process. On November 24, 2010, and acting pursuant to applicable FERC regulations and rules, FGCO initiated the relicensing process by filing its notice of intent to relicense and PAD in the license docket.

On November 30, 2010, the Seneca Nation filed its notice of intent to relicense and PADs necessary for them to submit a competing application. Section 15 of the FPA contemplates that third parties may file a "competing application" to assume ownership and operation of a hydroelectric facility upon (i) relicensure and (ii) payment of net book value of the plant to the original owner/operator. Nonetheless, FGCO believes it is entitled to a statutory “incumbent preference” under Section 15.

The Seneca Nation and certain other intervenors have asked FERC to redefine the “project boundary” of the hydroelectric plant to include the dam and reservoir facilities operated by the U.S. Army Corps of Engineers. On May 16, 2011, FirstEnergy filed a Petition for Declaratory Order with FERC seeking an order to exclude the dam and reservoir facilities from the project. The Seneca Nation, the New York State Department of Environmental Conservation, and the U.S. Department of Interior each submitted responses to FirstEnergy's petition, including motions to dismiss FirstEnergy's petition. The “project boundary” issue is pending before FERC.

On September 12, 2011, FirstEnergy and the Seneca Nation each filed “Revised Study Plan” documents. These documents describe the parties' respective proposals for the scope of the environmental studies that should be performed as part of the relicensing process. On October 11, 2011, FERC Staff issued a letter order that addressed the Revised Study Plans. In the order, FERC Staff approved FirstEnergy's Revised Study Plan, subject to a finding that the Project is located on “aboriginal lands” of the Seneca Nation. Based on this finding, FERC Staff directed FirstEnergy to consult with the Seneca Nation and other parties about the data set, methodology, and modeling of the hydrological impacts of project operations. FirstEnergy is performing the work necessary to develop a study proposal from which to conduct such consultations. The study process will extend through approximately November of 2013.


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FirstEnergy cannot predict the outcome of this matter or estimate the possible loss or range of loss.
ENVIRONMENTAL MATTERS
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. Compliance with environmental regulations could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that FirstEnergy 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.
CAA Compliance
FirstEnergy is required to meet federally-approved SO2and NOx emissions regulations under the CAA. FirstEnergy complies with SO2and NOx reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, combustion controls and post-combustion controls, generating more electricity from lower or non-emitting plants and/or using emission allowances. Violations can result in the shutdown of the generating unit involved and/or civil or criminal penalties.
In July 2008,threecomplaints were filed against FGCO in the U.S. District Court for the Western District of Pennsylvania seeking damages based on air emissions from the coal-fired Bruce Mansfield Plant.Twoof these 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 oftwenty-oneindividuals and the other being a class action complaint seeking certification as a class action with theeightnamed plaintiffs as the class representatives. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these complaints.
The states of New Jersey and Connecticut filed CAA citizen suits in 2007 alleging NSR violations at the coal-fired Portland Generation Station against GenOn Energy, Inc. (formerly RRI Energy, Inc. and the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999) and Met-Ed. Specifically, these suits allege that “modifications” at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR permitting in violation of the CAA's PSD program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. In September 2009, the Court granted Met-Ed's motion to dismiss New Jersey's and Connecticut's claims for injunctive relief against Met-Ed, but denied Met-Ed's motion to dismiss the claims for civil penalties. The parties dispute the scope of Met-Ed's indemnity obligation to and from Sithe Energy, and Met-Ed is unable to predict the outcome of this matter or estimate the possible loss or range of loss.
In January 2009, the EPA issued a NOV to GenOn Energy, Inc. alleging NSR violations at the coal-fired Portland Generation Station based on “modifications” dating back to 1986. The NOV also alleged NSR violations at the Keystone and Shawville coal-fired plants based on “modifications” dating back to 1984. Met-Ed, JCP&L and Penelec are unable to predict the outcome of this matter or estimate the possible loss or range of loss.
In each of May and September 2010, New Jersey submitted interstate pollution transport petitions seeking to reduce Portland Generating Station air emissions under section 126 of the CAA. Based on the September 2010 petition, the EPA has finalized emissions limits and compliance schedules to reduce SO2air emissions by approximately 81% at the Portland Station by January 6, 2015. New Jersey's May 2010 petition is still under consideration by the EPA.
In June 2008, the EPA issued a Notice and Finding of Violation to Mission alleging that “modifications” at the coal-fired Homer City Plant occurred from 1988 to the present without preconstruction NSR permitting in violation of the CAA's PSD program. In May 2010, the EPA issued a second NOV to Mission, Penelec, NYSEG and others that have had an ownership interest in Homer City containing in all material respects allegations identical to those included in the June 2008 NOV. In January 2011, the DOJ filed a complaint against Penelec in the U.S. District Court for the Western District of Pennsylvania seeking injunctive relief against Penelec based on alleged “modifications” at Homer City between 1991 to 1994 without preconstruction NSR permitting in violation of the CAA's PSD and Title V permitting programs. The complaint was also filed against the former co-owner, NYSEG, and various current owners of Homer City, including EME Homer City Generation L.P. and affiliated companies, including Edison International. In addition, the Commonwealth of Pennsylvania and the States of New Jersey and New York intervened and have filed separate complaints regarding Homer City seeking injunctive relief and civil penalties. In January 2011, another complaint was filed against Penelec and the other entities described above in the U.S. District Court for the Western District of Pennsylvania seeking damages based on Homer City's air emissions as well as certification as a class action and to enjoin Homer City from operating except in a “safe, responsible, prudent and proper manner.” In October 2011, the Court dismissed all of the claims with prejudice of the U.S. and the Commonwealth of Pennsylvania and the States of New Jersey and New York and all of the claims of the private parties, without prejudice to re-file state law claims in state court, against all of the defendants, including Penelec.In December 2011, the U.S., the Commonwealth of Pennsylvania and the States of New Jersey and New York all filed notices appealing to the Third Circuit Court of Appeals. Penelec believes the claims are without merit and intends to defend itself against the allegations made in these complaints, but, at this time, is unable to predict the outcome of this matter or estimate the loss or possible range of loss. Mission is seeking indemnification from NYSEG and Penelec, the co-owners of Homer City prior to its sale in 1999. On February 13, 2012, the Sierra Club notified the current owner and operator of Homer City, Homer City OL1-OL8 LLC and EME Homer City Generation L.P., that it intends to file a CAA citizen suit regarding its Title V permit and SO2 emissions from the Homer City Plant.
In August 2009, the EPA issued a Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, including the


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PSD, NNSR and Title V regulations, at the Eastlake, Lakeshore, Bay Shore and Ashtabula coal-fired plants. The EPA's NOV alleges equipment replacements during maintenance outages dating back to 1990 triggered the pre-construction permitting requirements under the PSD and NNSR programs. FGCO also received a request for certain operating and maintenance information and planning information for these same generating plants and notification that the EPA is evaluating whether certain maintenance at the Eastlake Plant may constitute a major modification under the NSR provisions of the CAA. Later in 2009, FGCO also received another information request regarding emission projections for the Eastlake Plant. In June 2011, EPA issued another Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, specifically opacity limitations and requirements to continuously operate opacity monitoring systems at the Eastlake, Lakeshore, Bay Shore and Ashtabula coal-fired plants. Also, in June 2011, FirstEnergy received an information request pursuant to section 114(a) of the CAA for certain operating, maintenance and planning information, among other information regarding these plants. 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 or estimate the possible loss or range of loss.
In August 2000, AE received an information request pursuant to section 114(a) of the CAA from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the followingtencoal-fired plants, which collectively include22electric generation units: Albright, Armstrong, Fort Martin, Harrison, Hatfield's Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island to determine compliance with the NSR provisions under the CAA, which can require the installation of additional air emission control equipment when a major modification of an existing facility results in an increase in emissions. AE has provided responsive information to this and a subsequent request but is unable to predict the outcome of this matter or estimate the possible loss or range of loss.
In May 2004, AE, AE Supply, MP and WP received a Notice of Intent to Sue Pursuant to CAA §7604 from the Attorneys General of New York, New Jersey and Connecticut and from the PA DEP, alleging that Allegheny performed major modifications in violation of the PSD provisions of the CAA at the following West Virginia coal-fired generation units: Albright Unit 3; Fort Martin Units 1 and 2; Harrison Units 1, 2 and 3; Pleasants Units 1 and 2 and Willow Island Unit 2. The Notice also alleged PSD violations at the Armstrong, Hatfield's Ferry and Mitchell coal-fired plants in Pennsylvania and identifies PA DEP as the lead agency regarding those facilities. In September 2004, AE, AE Supply, MP and WP received a separate Notice of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.
In June 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed suit against AE, AE Supply, MP, PE and WP in the United States District Court for the Western District of Pennsylvania alleging, among other things, that Allegheny performed major modifications in violation of the CAA and the Pennsylvania Air Pollution Control Act at the coal-fired Hatfield's Ferry, Armstrong and Mitchell Plants in Pennsylvania. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. A non-jury trial on liability only was held in September 2010. Plaintiffs filed their proposed findings of fact and conclusions of law in December 2010, Allegheny made its related filings in February 2011 and plaintiffs filed their responses in April 2011. The parties are awaiting a decision from the District Court, but there is no deadline for that decision and we are unable to predict the outcome or estimate the possible loss or range of loss.
In September 2007, Allegheny received a NOV from the EPA alleging NSR and PSD violations under the CAA, as well as Pennsylvania and West Virginia state laws at the coal-fired Hatfield's Ferry and Armstrong plants in Pennsylvania and the coal-fired Fort Martin and Willow Island plants in West Virginia.
FirstEnergy intends to vigorously defend against the CAA matters described above but cannot predict their outcomes or estimate the possible loss or range of loss.
State Air Quality Compliance
In early 2006, Maryland passed the Healthy Air Act, which imposes state-wide emission caps on SO2and NOx, requires mercury emission reductions and mandates that Maryland join the RGGI and participate in that coalition's regional efforts to reduce CO2emissions. On April 20, 2007, Maryland became the tenth state to join the RGGI. The Healthy Air Act provides a conditional exemption for the R. Paul Smith coal-fired plant for NOx, SO2and mercury, based on a 2006 PJM declaration that the plant is vital to reliability in the Baltimore/Washington DC metropolitan area. Pursuant to the legislation, the MDE passed alternate NOx and SO2limits for R. Paul Smith, which became effective in April 2009. However, R. Paul Smith is still required to meet the Healthy Air Act mercury reductions of80%which began in 2010. The statutory exemption does not extend to R. Paul Smith's CO2emissions. Maryland issued final regulations to implement RGGI requirements in February 2008.FourteenRGGI auctions have been held through the end of calendar year 2011. RGGI allowances are also readily available in the allowance markets, affording another mechanism by which to secure necessary allowances. On March 14, 2011, MDE requested PJM perform an analysis to determine if termination of operation at R. Paul Smith would adversely impact the reliability of electrical service in the PJM region under current system conditions. On June 30, 2011, PJM notified MDE that termination of operation at R. Paul Smith would adversely impact the reliability of electrical service in the PJM region absent transmission system upgrades. On January 26, 2012, FirstEnergy announced that R. Paul Smith is among nine coal-fired plants it intends to retire by September 1, 2012, subject to review of reliability impacts by PJM. FirstEnergy is unable to predict the outcome of this matter or estimate the possible loss or range of loss.
In January 2010, the WVDEP issued a NOV for opacity emissions at the Pleasants coal-fired plant. In August 2011, FirstEnergy and WVDEP resolved the NOV through a Consent Order requiring installation of a reagent injection system to reduce opacity by September 2012.


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National Ambient Air Quality Standards
The EPA's CAIR requires reductions of NOx and SO2emissions intwophases (2009/2010 and 2015), ultimately capping SO2emissions in affected states to2.5 milliontons annually and NOx emissions to1.3 milliontons annually. In 2008, the U.S. Court of Appeals for the District of Columbia vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” In December 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 opinion. The Court ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOx SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the “8-hour” ozone NAAQS. In July 2011, the EPA finalized the CSAPR, to replace CAIR,requiring reductions of NOx and SO2emissions intwo phases (2012 and 2014), ultimately capping SO2emissions in affected states to2.4 milliontons annually and NOx emissions to1.2 milliontons annually. CSAPR allows trading of NOx and SO2emission allowances between power plants located in the same state and interstate trading of NOx and SO2emission allowances with some restrictions. On February 21, 2012, the EPA revised certain CASPR state budgets (for Florida, Louisiana, Michigan, Mississippi, Nebraska, New Jersey, New York, Texas, and Wisconsin and new unit set-asides in Arkansas and Texas), certain generating unit allocations (for some units in Alabama, Indiana, Kansas, Kentucky, Ohio and Tennessee) for NOx and SO2emissions and delayed from 2012 to 2014 certain allowance penalties that could apply with respect to interstate trading of NOx and SO2emission allowances.On December 30, 2011, CSAPR was stayed by the U.S. Court of Appeals for the District of Columbia Circuit pending a decision on legal challenges raised in appeals filed by various stakeholders and scheduled to be argued before the Court on April 13, 2012. The Court ordered EPA to continue administration of CAIR until the Court resolves the CSAPR appeals. Depending on the outcome of these proceedings and how any final rules are ultimately implemented, FGCO's and AE Supply's future cost of compliance may be substantial and changes to FirstEnergy's operations may result.

During 2011, FirstEnergy recorded pre-tax impairment charges of approximately$6 million($1 millionfor FES and$5 millionfor AE Supply) for NOx emission allowances that were expected to be obsolete after 2011 and approximately$21 million($18 millionfor FES and$3 millionfor AE Supply) for excess SO2emission allowances in inventory that it expects will not be consumed in the future.
Hazardous Air Pollutant Emissions
On December 21, 2011, the EPA finalized the MATS to establish emission standards for mercury, hydrochloric acid and various metals for electric generating units. The MATS establishes emission limits for mercury, PM, and HCL for all existing and new coal-fired electric generating units effective in April 2015 and allows averaging of emissions from multiple units located at a single plant. Under the CAA, state permitting authorities can grant an additional compliance year through April 2016, as needed, including instances when necessary to maintain reliability where electric generating units are being closed. In addition, an EPA enforcement policy document contemplates up to an additional year to achieve compliance, through April 2017, under certain circumstances for reliability critical units. On January 26, 2012 and February 8, 2012, FGCO, MP and AE Supply announced the retirement by September 1, 2012 (subject to a reliability review by PJM) of nine coal-fired power plants (Albright, Armstrong, Ashtabula, Bay Shore except for generating unit 1, Eastlake, Lake Shore, R. Paul Smith, Rivesville and Willow Island) with a total capacity of3,349megawatts (generating, on average, approximately ten percent of the electricity produced by the companies over the past three years) due to MATS and other environmental regulations. In addition, MP will make a filing with the WVPSC to provide them with information regarding the retirement of its plants. Depending on how the MATS are ultimately implemented, FirstEnergy's future cost of compliance with MATS may be substantial and other changes to FirstEnergy's operations may result.
On February 24, 2012, PJM notified FirstEnergy of its preliminary analysis of the reliability impacts that may result from closure of the older competitive coal-fired generating units. PJM's preliminary analysis indicated that there would be significant reliability concerns that will need to be addressed. FirstEnergy intends to continue to actively engage in discussions with PJM regarding this notification, including the possible continued operation of certain plants.
Climate Change
There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. 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, in June 2009. Certain states, primarily the northeastern states participating in the RGGI and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.
In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that required FirstEnergy to measure and report GHG emissions commencing in 2010. In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA's finding concludes that concentrations of several key GHGs increase the threat of climate change and may be regulated as “air pollutants” under the CAA. In April 2010, the EPA finalized new 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 would not be triggered for electric generating plants and other stationary sources until January 2, 2011, at the earliest. In May 2010, the EPA finalized new thresholds for GHG emissions that define when permits under the CAA's NSR program would be required. The EPA established an emissions applicability threshold of75,000tons per year of CO2equivalents effective January 2, 2011, for existing facilities under the CAA's PSD program.


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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 man-made GHG, including CO2, emitted by developed countries by 2012. A December 2009 U.N. Climate Change Conference in Copenhagen did not reach a consensus on a successor treaty to the Kyoto Protocol, but did take note of the Copenhagen Accord, a non-binding political agreement that recognized the scientific view that the increase in global temperature should be belowtwodegrees Celsius; includes a commitment by developed countries to provide funds, approaching$30 billionover three years with a goal of increasing to$100 billionby 2020; and establishes the “Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. To the extent that 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 targets from 2020, while developing countries, including Brazil, China and India, would agree to take mitigation actions, subject to their domestic measurement, reporting and verification.A December 2011 U.N. Climate Change Conference in Durban, Africa, established a negotiating process to develop a new post-2020 climate change protocol, called the “Durban Platform for Enhanced Action”. This negotiating process contemplates developed countries, as well as developing countries such as China, India, Brazil, and South Africa, to undertake legally binding commitments post-2020. In addition, certain countries agreed to extend the Kyoto Protocol for a second commitment period, commencing in 2013 and expiring in 2018 or 2020.
In 2009, the U.S. Court of Appeals for the Second Circuit and 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. 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. The U.S. Supreme Court granted a writ of certiorari to review the decision of the Second Circuit. On June 20, 2011, the U.S. Supreme Court reversed the Second Circuit but failed to answer the question of the extent to which actions for damages based on GHG emissions may remain viable. The Court remanded to the Second Circuit the issue of whether the CAA preempted state common law nuisance actions.
FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO2emissions per KWH of electricity generated by FirstEnergy is lower than many of its regional competitors due to its diversified generation sources, which include low or non-CO2emitting gas-fired and nuclear generators.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal CWA and its amendments, apply to FirstEnergy's plants. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy's operations.
In 2004, the EPA established new performance standards under Section 316(b) of the CWA for reducing impacts on fish and shellfish from cooling water intake structures at certain existing electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). In 2007, the Court of Appeals for the Second Circuit invalidated portions of the Section 316(b) performance standards and the EPA has taken the position 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. In April 2009, the U.S. Supreme Court reversed one significant aspect of the Second Circuit's opinion and decided that Section 316(b) of the CWA authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. On March 28, 2011, the EPA released a new proposed regulation under Section 316(b) of the CWA generally requiring fish impingement to be reduced to a12%annual average and studies to be conducted at the majority of our existing generating facilities to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic life. On July 19, 2011, the EPA extended the public comment period for the new proposed Section 316(b) regulation by30days but stated its schedule for issuing a final rule remains July 27, 2012. FirstEnergy is studying various control options and their costs and 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. 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.
In April 2011, the U.S. Attorney's Office in Cleveland, Ohio advised FGCO that it is no longer considering prosecution under the CWA 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. On August 5, 2011, EPA issued an information request pursuant to Sections 308 and 311 of the CWA for certain information pertaining to the oil spills and spill prevention measures at FirstEnergy facilities. FirstEnergy responded on October 10, 2011. On February 1, 2012, FirstEnergy executed a tolling agreement with the EPA extending the statute of limitations to July 31, 2012. FGCO does not anticipate any losses resulting from this matter to be material.
In May 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club filed a CWA citizen suit alleging violations of arsenic limits in the NPDES water discharge permit for the fly ash impoundments at the Albright Station seeking unspecified civil penalties and injunctive relief. The MP filed an answer on July 11, 2011, and a motion to stay the proceedings


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on July 13, 2011. On January 3, 2012, the Court denied MP's motion to dismiss or stay the CWA citizen suit but without prejudice to re-filing in the future. MP is currently seeking relief from the arsenic limits through WVDEP agency review.
In June 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club served a60-Day Notice of Intent required prior to filing a citizen suit under the CWA for alleged failure to obtain a permit to construct the fly ash impoundments at the Albright Plant.
FirstEnergy intends to vigorously defend against the CWA matters described above but, except as indicated above, cannot predict their outcomes or estimate the possible loss or range of loss.
Monongahela River Water Quality
In late 2008, the PA DEP imposed water quality criteria for certain effluents, including TDS and sulfate concentrations in the Monongahela River, on new and modified sources, including the scrubber project at the coal-fired Hatfield's Ferry Plant. These criteria are reflected in the current PA DEP water discharge permit for that project. AE Supply appealed the PA DEP's permitting decision, which would require it to incur estimated costs in excess of$150 millionin order to install technology to meet TDS and sulfate limits in the permit or negatively affect its ability to operate the scrubbers as designed. The permit has been independently appealed by Environmental Integrity Project and Citizens Coal Council, which seeks to impose more stringent technology-based effluent limitations. Those same parties have intervened in the appeal filed by AE Supply, and both appeals have been consolidated for discovery purposes. An order has been entered that stays the permit limits that AE Supply has challenged while the appeal is pending. A hearing on the parties' appeals was scheduled to begin in September 2011, however the Court stayed all prehearing deadlines on July 15, 2011 to allow the parties additional time to work out a settlement, and has rescheduled a hearing, if necessary, for July 2012. If these settlement discussions are successful, AE Supply anticipates that its obligations will not be material. AE Supply intends to vigorously pursue these issues, but cannot predict the outcome of these appeals or estimate the possible loss or range of loss.
In a parallel rulemaking, the PA DEP recommended, and in August 2010, the Pennsylvania Environmental Quality Board issued, a final rule imposing end-of-pipe TDS effluent limitations. FirstEnergy could incur significant costs for additional control equipment to meet the requirements of this rule, although its provisions do not apply to electric generating units until the end of 2018, and then only if the EPA has not promulgated TDS effluent limitation guidelines applicable to such units.
In December 2010, PA DEP submitted its CWA 303(d) list to the EPA with a recommended sulfate impairment designation for an approximately68mile stretch of the Monongahela River north of the West Virginia border. In May 2011, the EPA agreed with PA DEP's recommended sulfate impairment designation. PA DEP's goal is to submit a final water quality standards regulation, incorporating the sulfate impairment designation for EPA approval by May, 2013. PA DEP will then need to develop a TMDL limit for the river, a process that will take approximatelyfiveyears. Based on the stringency of the TMDL, FirstEnergy may incur significant costs to reduce sulfate discharges into the Monongahela River from the coal-fired Hatfield's Ferry and Mitchell Plants in Pennsylvania and the coal-fired Fort Martin Plant in West Virginia.
In October 2009, the WVDEP issued the water discharge permit for the Fort Martin Plant. Similar to the Hatfield's Ferry water discharge permit, the Fort Martin permit imposes effluent limitations for TDS and sulfate concentrations. The permit also imposes temperature limitations and other effluent limits for heavy metals that are not contained in the Hatfield's Ferry water discharge permit. Concurrent with the issuance of the Fort Martin permit, WVDEP also issued an administrative order that sets deadlines for MP to meet certain of the effluent limits that are effective immediately under the terms of the permit. MP appealed the Fort Martin permit and the administrative order. The appeal included a request to stay certain of the conditions of the permit and order while the appeal is pending, which was granted pending a final decision on appeal and subject to WVDEP moving to dissolve the stay. The appeals have been consolidated. MP moved to dismiss certain of the permit conditions for the failure of the WVDEP to submit those conditions for public review and comment during the permitting process. An agreed-upon order that suspends further action on this appeal, pending WVDEP's release for public review and comment on those conditions, was entered on August 11, 2010. The stay remains in effect during that process. The current terms of the Fort Martin permit would require MP to incur significant costs or negatively affect operations at Fort Martin. Preliminary information indicates an initial capital investment in excess of the capital investment that may be needed at Hatfield's Ferry in order to install technology to meet the TDS and sulfate limits in the Fort Martin permit, which technology may also meet certain of the other effluent limits in the permit. Additional technology may be needed to meet certain other limits in the permit. MP intends to vigorously pursue these issues but cannot predict the outcome of these appeals or estimate the possible loss or range of loss.
Regulation of Waste Disposal
Federal 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. Certain fossil-fuel combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. In February 2009, the EPA requested comments from the states on options for regulating coal combustion residuals, including whether they should be regulated as hazardous or non-hazardous waste.
In December 2009, in an advance notice of public rulemaking, the EPA asserted that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. In May 2010, the EPA proposedtwooptions for additional


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regulation of coal combustion residuals, including the option of regulation as a special waste under the EPA's hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. FirstEnergy's future cost of compliance with any coal combustion residuals regulations that 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. Compliance with those regulations could have an adverse impact on FirstEnergy's results of operations and financial condition.
LBR CCB impoundment is expected to run out of disposal capacity for disposal of CCBs from the BMP between 2016 and 2018. BMP is pursuing several CCB disposal options.
Certain of our 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 ofDecember 31, 2011, based on estimates of the total costs of cleanup, the Utility Registrants' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay.Total liabilities of approximately$106 million(JCP&L -$70 million, TE -$1 million, CEI -$1 million, FGCO -$1 millionand FE -$33 million) have been accrued throughDecember 31, 2011. Included in the total are accrued liabilities of approximately$63 millionfor 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. On July 11, 2011, FirstEnergy was found to be a potentially responsible party under CERCLA, indirectly liable for a portion of past and future clean-up costs at certain legacy MGP sites, estimated to total approximately$59 million. FirstEnergy recognized an additional expense of$29 millionduring the second quarter of 2011;$30 millionhad previously been reserved prior to 2011.FirstEnergy determined that it is reasonably possible that it or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the possible losses or range of losses cannot be determined or reasonably estimated at this time.
OTHER LEGAL PROCEEDINGS

Power Outages and Related Litigation

In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. &L.Twoclass 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.

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After various motions, rulings and appeals, the Plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, strict product liability and punitive damages were dismissed, leaving only the negligence and breach of contract causes of actions. The class was decertified twice by the trial court, and appealed both times by the Plaintiffs, with the results being that: (1)On July 29, 2010, the Appellate Division limited the class only to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation which resulted in planned and unplanned outages in the area during a 2-3 day period, and (2) in March 2007, the Appellate Division remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. On March 31, 2009, the trial court again granted JCP&L’s motion to decertify the class. On April 20, 2009, the Plaintiffs filed a motion for leave to take an interlocutory appeal to the trial court's decision to decertify the class, which was granted by the Appellate Division on June 15, 2009. Plaintiffs filed their appellate brief on August 25, 2009, and JCP&L filed an opposition brief on September 25, 2009. On or about October 13, 2009, Plaintiffs filed their reply brief in further support of their appeal ofupheld the trial court's decision decertifying the class. In November 2010, the Supreme Court issued an order denying Plaintiffs' motion for leave to appeal. The Appellate Division heard oral argument on January 5, 2010, beforeCourt's order effectively ends the attempt to certify the class, and leaves only9plaintiffs to pursue their respective individual claims. The matter was referred back to the lower court, which set a three-judge panel. JCP&Ltrial date for February 13, 2012, for the remaining individual plaintiffs. Plaintiffs have accepted an immaterial amount in final settlement of all matters and the settlement documentation is awaiting the Court’s decision.

being finalized for execution by all parties.
Nuclear Plant Matters

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

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As ofDecember 31, 2009,2011, FirstEnergy had approximately $1.9$2 billioninvested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy provided an additional $80 million parental guarantee associated with the funding of decommissioning costs for these units and indicated that it planned to contribute an additional $80 million to these trusts by 2010. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy’s nuclear decommissioning trustsFirstEnergy's NDT fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy’sFirstEnergy's obligation to fund the trusts may increase. Disruptions in the capital markets and itstheir effects on particular businesses and the economy in generalcould also affectsaffect the values of the NDT. On March 28, 2011, FENOC submitted its biennial report on nuclear decommissioning trusts. On June 18, 2009,funding to the NRC informed FENOC that its review tentatively concluded thatNRC. This submittal identified a total shortfall existed in the decommissioning trust fund for Beaver Valley Unit 1. On November 24, 2009, FENOC submitted a revisednuclear decommissioning funding calculation using the NRC formula method based on the renewed license for Beaver Valley Unit 1 and Perry of approximately$92.5 million. By letter dated December 29, 2011, FENOC informed the NRC staff that it had increased the parental guarantee to$95 million.
In January 2004, subsidiaries of FirstEnergy filed a lawsuit in the U.S. Court of Federal Claims seeking damages in connection with costs incurred at the Beaver Valley, Davis-Besse and Perry nuclear facilities as a result of the DOE's failure to begin accepting spent nuclear fuel on January 31, 1998. DOE was required to begin accepting spent nuclear fuel by the Nuclear Waste Policy Act (42 USC 10101 et seq) and the contracts entered into by the DOE and the owners and operators of these facilities pursuant to the Act.In January 2012, the applicable FirstEnergy affiliates reached a$48 millionsettlement of these claims.

In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse operating license for an additional twenty years, until 2037. By an order dated April 26, 2011, a NRC ASLB granted a hearing on the Davis-Besse license renewal application to a group of petitioners. By this order, the ASLB also admitted two contentions challenging whether FENOC's Environmental Report adequately evaluated (1) a combination of renewable energy sources as alternatives to the renewal of Davis-Besse's operating license, and (2) severe accident mitigation alternatives at Davis-Besse. On May 6, 2011, FENOC filed an appeal with the NRC from the order granting a hearing on the Davis-Besse license renewal application.On January 10, 2012, intervenors petitioned the ASLB for a new contention on the cracking of the Davis-Besse shield building discussed below.


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On October 1, 2011, Davis-Besse was safely shut down for a scheduled outage to install a new reactor vessel head and complete other maintenance activities. The new reactor head, which extended operations until 2036. FENOC’s submittal demonstrated that therereplaced a head installed in 2002, enhances safety and reliability, and features control rod nozzles made of material less susceptible to cracking. On October 10, 2011, following opening of the building for installation of the new reactor head, a sub-surface hairline crack was a de minimis shortfall. identified in one of the exterior architectural elements on the shield building. These elements serve as architectural features and do not have structural significance. During investigation of the crack at the shield building opening, concrete samples and electronic testing found similar sub-surface hairline cracks in most of the building's architectural elements. FENOC's investigation also identified other indications. Included among them were sub-surface hairline cracks in the upper portion of the shield building (above elevation 780') and in the vicinity of the main steam line penetrations.A team of industry-recognized structural concrete experts and Davis-Besse engineers has determined these conditions do not affect the facility's structural integrity or safety.
On December 2, 2011, the NRC issued a CAL which concluded that FENOC provided "reasonable assurance that the shield building remains capable of performing its safety functions." The CAL imposed a number of commitments from FENOC including, submitting a root cause evaluation and corrective actions to the NRC by February 28, 2012, and further evaluations of the shield building. On February 27, 2012, FENOC sent the root cause evaluation to the NRC. Finally, the CAL also stated that the NRC was still evaluating whether the current condition of the shield building conforms to the plant's licensing basis. On December 6, 2011, the Davis-Besse plant returned to service.
By letter dated August 25, 2011, the NRC made a final significance determination (white) associated with a violation that occurred during the retraction of a source range monitor from the Perry reactor vessel. The NRC also placed Perry in the degraded cornerstone column (Column 3) of the NRC's Action Matrix governing the oversight of commercial nuclear reactors. As a result, the NRC staff will conduct several supplemental inspections, culminating in an inspection using Inspection Procedure 95002 to determine if the root cause and contributing causes of risk significant performance issues are understood, the extent of condition has been identified, whether safety culture contributed to the performance issues, and if FENOC's corrective actions are sufficient to address the causes and prevent recurrence.
In light of the impacts of the earthquake and tsunami on the reactors in Fukushima, Japan, the NRC conducted inspections of emergency equipment at U.S. reactors. The NRC also established a Near-Term Task Force to review its processes and regulations in light of the incident, and, on July 12, 2011, the Task Force issued its report of recommendations for regulatory changes. On October 18, 2011, the NRC approved the Staff recommendations, and directed the Staff to implement its near-term recommendations without delay. Ultimately, the adoption of the Staff recommendations on near-term actions is likely to result in additional costs to implement plant modifications and upgrades required by the regulatory process over the next several years, which costs are likely to be material.
On February 16, 2012, the NRC issued a request for information to the licensed operators of 11 2009,nuclear power plants, including Beaver Valley Power Station Units 1 and 2, with respect to the NRC’s reviewmodeling of FirstEnergy’s methodologyfuel performance as it relates to "thermal conductivity degradation," which is the potential in older fuel for reduced capacity to transfer heat that could potentially change its performance during various accident scenarios, including loss of coolant accidents. The request for information indicated that this phenomenon has not been accounted for adequately in performance models for the fundingfuel developed by the fuel manufacturer. The NRC is requesting that FENOC provide an analysis to demonstrate that the NRC regulations are being met. Absent that demonstration, the request indicates that the NRC may consider imposing restrictions on reactor operating limits until the issue is satisfactorily resolved.
ICG Litigation
On December 28, 2006, AE Supply and MP filed a complaint in the Court of decommissioningCommon Pleas of this facility concluded that there was reasonable assuranceAllegheny County, Pennsylvania against ICG, Anker WV, and Anker Coal. Anker WV entered into a long term Coal Sales Agreement with AE Supply and MP for the supply of adequate decommissioning funding atcoal to the Harrison generating facility. Prior to the time permanent termination of operationstrial, ICG was dismissed as a defendant by the Court, which issue can be the subject of a future appeal. As a result of defendants' past and continued failure to supply the contracted coal, AE Supply and MP have incurred and will continue to incur significant additional costs for purchasing replacement coal. A non-jury trial was held from January 10, 2011 through February 1, 2011. At trial, AE Supply and MP presented evidence that they have incurred in excess of$80 millionin damages for replacement coal purchased through the end of 2010 and will incur additional damages in excess of$150 millionfor future shortfalls. Defendants primarily claim that their performance is expected. FirstEnergy continuesexcused under a force majeure clause in the coal sales agreement and presented evidence at trial that they will continue to evaluatenot provide the statuscontracted yearly tonnage amounts. On May 2, 2011, the court entered a verdict in favor of its funding obligationsAE Supply and MP for$104 million($90 millionin future damages and$14 millionfor replacement coal / interest). Post-trial filings occurred in May 2011, with Oral Argument on June 28, 2011. On August 25, 2011, the decommissioningAllegheny County Court denied all Motions for Post-Trial relief and the May 2, 2011 verdict became final. On August 26, 2011, ICG posted bond and filed a Notice of these nuclear facilities.Appeal. Briefing on the Appeal is concluded with oral argument expected in May or June of 2012. AE Supply and MP intend to vigorously pursue this matter through appeal.

Other Legal Matters

In February 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 reduction 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 approved by the PUCO. In March 2010, the named-defendant companies filed a motion to dismiss the case due to the lack of jurisdiction of the court of common


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pleas. The court granted the motion to dismiss on September 7, 2010. The plaintiffs appealed the decision to the Court of Appeals of Ohio.On October 21, 2011, the Court of Appeals rendered its decision affirming the dismissal of the Complaint by the Court of Common Pleas on all counts except for one relating to an allegation of fraud. The Companies timely filed a notice of appeal on December 5, 2011 with the Supreme Court of Ohio challenging this one aspect of the Court of Appeals opinion. The Supreme Court of Ohio has not yet acted on the appeal.

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.under Note 15, Regulatory Matters.

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

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. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss and if such estimate can be made. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced above, matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

We prepare ourFirstEnergy prepares consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. AllFirstEnergy's accounting policies require significant judgment regarding estimates and assumptions underling the amounts included in the financial statements. Additional information regarding the application of our assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Our more significant accounting policies are described below.included in the Combined Notes to the Consolidated Financial Statements.

Revenue Recognition

We followFirstEnergy follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled sales is recognized. The determination of unbilled sales and revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, demand by customer class, applicable billing demands, weather-related impacts, number of days unbilled and pricestariff rates in effect forwithin each customer class.

Regulatory Accounting

Our energy delivery services segment isFirstEnergy’s regulated distribution and regulated independent transmission segments are subject to regulationregulations that sets the prices (rates) wethe Utilities, ATSI, TrAIL and PATH are permitted to charge our customers based on costs that the regulatory agencies determine we are permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This ratemaking process results in the recording of regulatory assets and liabilities based on anticipated future cash inflows. Weinflows and outflows. FirstEnergy regularly reviewreviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future.

PensionPensions and Other Postretirement BenefitsOPEB Accounting

Our reported costs of providingFirstEnergy 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 provides a portion of non-contributory pre-retirement basic life insurance for employees who are eligible to retire. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.
As described in Note 1, Organization, Basis of Presentation and Significant Accounting Policies, FirstEnergy elected to change its method of recognizing actuarial gains and losses for its defined benefit pension benefitsplans and OPEB benefits other than pensions are dependent upon numerous factors resulting from actual plan experienceplans effective in 2011. Previously, FirstEnergy recognized the net actuarial gains and certain assumptions.

Pensionlosses as a component of AOCI and OPEB costs are affected by employee demographics (including age, compensation levels,amortized the gains and employment periods), the level of contributions we make to the plans and earnings on plan assets. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs.

In accordance with GAAP, changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on thelosses into income statement, but generally are recognized in future years over the remaining average service periodlife of affected employees within the related plans, to the extent such gains and losses were outside a corridor of the greater of 10% of the market-related value of plan participants. GAAP delays recognitionassets or 10% of changes duethe plans' projected benefit obligation.

FirstEnergy has elected to immediately recognize the long-term naturechange in the fair value of plan assets and net actuarial gains and losses annually in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. The remaining components of pension and OPEB obligationsexpense, primarily service, interest, assumed return on assets and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEBprior service costs, will be recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience.on a quarterly basis.


We recognize100


FirstEnergy's funding policy is based on actuarial computations using the overfunded or underfunded statusprojected unit credit method. During 2011, FirstEnergy made pre-tax contributions to its qualified pension plans of our defined benefit$372 million. FirstEnergy made an additional $600 million pre-tax contribution to its qualified pension and other postretirement benefit plansplan on the balance sheet and recognize changes in funded status in the year in which the changes occur through other comprehensive income.January 5, 2012. The underfunded status of ourFirstEnergy’s qualified and non-qualified pension and OPEB plans atas of December 31, 2009 is $1.32011 was $2.6 billion.

As a result of the merger with AE in 2011, FirstEnergy assumed certain pension and OPEB plans. FirstEnergy measured the funded status of the Allegheny pension plans and OPEB plans as of the merger closing date using discount rates of 5.50% and 5.25%, respectively. The fair values of plan assets for Allegheny's pension plans and OPEB plans at the date of the merger were $954 million and $75 million, respectively, and the actuarially determined benefit obligations for such plans as of that date were $1,341 million and $272 million, respectively. The expected returns on plan assets used to calculate net periodic costs for periods in 2011 subsequent to the date of the merger are 8.25% for Allegheny's qualified pension plan and 5.00% for Allegheny's OPEB plans.
In selecting an assumed discount rate, we considerFirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefitOPEB obligations. As of December 31, 2009, theThe assumed discount rates for pensionpensions were 5.00%, 5.50% and OPEB were 6.0%6.00% as of December 31, 2011, 2010 and 5.75%,2009, respectively. The assumed discount rates for both pension and OPEB were 7.0%4.75%, 5.00% and 6.5%5.75% as of December 31, 2008,2011, 2010 and 2007,2009, respectively.

OurFirstEnergy’s assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by ourthe pension trusts. In 2009 our2011, FirstEnergy’s qualified pensionpensions and OPEB plan assets actually earned $570$387 million or 13.6% and lost $1.4 billion6.05% compared to amounts earned of $492 million, or 23.8%10.1% in 2008. Our2010. The qualified pension and OPEB costs in 20092011 and 20082010 were computed using an assumed 9.0%8.25% and 8.50% rate of return, respectively, on plan assets which generated $379$486 million and $514$397 million of expected returns on plan assets, respectively. The expected return of pensionpensions and OPEB assets is based on the trusts’ asset allocation targets and the historical performance of risk-based and fixed income securities. The gains or losses generated as a result of the difference between expected and actual returns on plan assets are deferred and amortized and will increase or decrease future net periodic pension and OPEB cost respectively.as the difference is recognized annually in the fourth quarter of each fiscal year.

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Our qualifiedBased on discounts rates of 5.00% for pension, 4.75% for OPEB and non-qualified pension and OPEBan estimated return on assets of 7.75%, FirstEnergy expects its 2012 pre-tax net periodic postemployment benefit cost was $197 million in 2009 compared to credits of $116 million in 2008 and $73 million in 2007. On September 2, 2009, the Utilities and ATSI made a combined $500 million voluntary contribution to their qualified pension plan. Due to the significance of the voluntary contribution, we elected to remeasure our qualified pension plan as of August 31, 2009. On January 2, 2007, we made a $300 million voluntary contribution to our pension plan. In addition, during 2006, we amended our OPEB plan, effective in 2008, to cap our monthly contribution for many of the retirees and their spouses receiving subsidized health care coverage. On June 2, 2009, we further amended our health care benefits plan for all employees and retirees eligible that participate in that plan. The 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. In the third quarter of 2009, FirstEnergy also incurred a $13 million net postretirement benefit cost (including amounts capitalized) related to a 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. We expect our 2010 qualified and non-qualified pension and OPEB costs (including amounts capitalized) to be $138 million.approximately $117 million (excluding any actuarial mark-to-market adjustments that would be recognized in 2012). The following table reflects the portion of pensions and OPEB costs that were charged to expense in the three years ended December 31, 2011.

Postemployment Benefits Expense (Credits) 2011 2010 2009
  (In millions)
Pensions $555
 $247
 $377
OPEB (112) (126) (57)
Total $443
 $121
 $320
Health care cost trends continue to increase and will affect future OPEB costs. The 2009 and 20082011 composite health care trend rate assumptions were approximately 8.5-10% and 9-11%7.5-8.5%, respectively,compared to 8.0-9.0% in 2010, gradually decreasing to 5% in later years. In determining ourFirstEnergy’s trend rate assumptions, we included are the specific provisions of ourFirstEnergy’s health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in ourFirstEnergy’s health care plans, and projections of future medical trend rates. The effect on ourthe pension and OPEB costs from changes in key assumptions are as follows:

Increase in Net Periodic Benefit Costs from Adverse Changes in Key Assumptions
Increase in Costs from Adverse Changes in Key Assumptions 
  
Assumption Adverse Change Pension  OPEB  Total 
    (In millions) 
Discount rate
 
Decrease by 0.25%
  $12  $1  $13 
Long-term return on assets
 
Decrease by 0.25%
  $11  $1  $12 
Health care trend rate
 
Increase by 1%
   N/A  $4  $4 

Assumption Adverse Change Pensions OPEB Total
      (In millions)  
Discount rate Decrease by 0.25% $236
 $23
 $259
Long-term return on assets Decrease by 0.25% $16
 $1
 $17
Health care trend rate Increase by 1.0% N/A
 $27
 $27
Emission Allowances

We holdFirstEnergy holds emission allowances for SO2and NOXNOx in order to comply with programs implemented by the EPA designed to regulate emissions of SO2 and NOXNOx produced by power plants. Emission allowances are either granted to us by the EPA at zero cost or are purchased at fair value as needed to meet emission requirements. Emission allowances are not purchased with the intent of resale. Emission allowances eligible to be used in the current year are recorded in materials and supplies inventory at the lesser oftheir weighted average cost or market value.cost. Emission allowances eligible for use in future years are recorded as other investments. We recognizeFirstEnergy recognizes emission allowance costs as fuel expense during the periods that emissions are produced by our generating facilities. Excess emissionEmission allowances that are not needed to meet emission requirements may be sold and are reported as a reduction to other operating expenses. Obsolete or excess emission allowances follow FirstEnergy's inventory practice that requires the emission allowances to be recorded at the lower of weighted average cost or market value. See Note 11, Impairment of Long-Lived Assets for further information on impairments of emission allowances.


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Long-Lived AssetsCommodity Price Risk

FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. FirstEnergy's Risk Management 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 practice. FirstEnergy uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.
We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amountThe valuation of such an asset may not be recoverable. The recoverability of a long-lived assetderivative contracts is measured by comparing the asset’s carrying valuebased on observable market information to the sumextent that such information is available. In cases where such information is not available, FirstEnergy relies on model-based information. The model provides estimates of undiscounted future cash flows expected to result from the useregional prices for electricity and eventual disposition of the asset. If the carrying value is greater than the undiscounted future cash flows of the long-lived asset an impairment exists and a loss is recognized for the amount by which the carrying value of the long-lived asset exceeds its estimated fair value. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

Asset Retirement Obligations

We recognize an ARO for the future decommissioning of our nuclear power plants and future remediation of other environmental liabilities associated with all of our long-lived assets. The ARO liability represents an estimate of therelated price volatility. FirstEnergy uses these results to develop estimates of fair value of our current obligation related to nuclear decommissioning and the retirement or remediation of environmental liabilities of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. We use an expected cash flow approach to measure the fair value of the nuclear decommissioning and environmental remediation ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plants' current license and settlement based on an extended license term and expected remediation dates.

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Income Taxes

We record income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery periodinternal management decision making (see Note 9, Fair Value Measurements of the related property. DeferredCombined Notes to the Consolidated Financial Statements). Sources of information for the valuation of commodity derivative contracts assets and liabilities as of December 31, 2011 are summarized by year in the following table:


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Source of Information-
Fair Value by Contract Year
 2012 2013 2014 2015 2016 Thereafter Total
  (In millions)
Prices actively quoted(1)
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Other external sources(2)
 (211) (51) (32) (22) —
 —
 (316)
Prices based on models (21) —
 —
 —
 8
 31
 18
Total(3)
 $(232) $(51) $(32) $(22) $8
 $31
 $(298)
(1)
Represents exchange traded New York Mercantile Exchange futures and options.
(2)
Primarily represents contracts based on broker and IntercontinentalExchange quotes.
(3)
Includes $(301) million in non-hedge commodity derivative contracts that are primarily related to NUG contracts. NUG contracts are subject to regulatory accounting and do not materially impact earnings.
FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. Based on derivative contracts held as of December 31, 2011, an adverse 10% change in commodity prices would decrease net income tax liabilitiesby approximately $13 million during the next 12 months.
Interest Rate Risk
FirstEnergy’s exposure to fluctuations in market interest rates is reduced since a significant portion of debt has fixed interest rates, as noted in the table below. FirstEnergy is subject to the inherent interest rate risks related to taxrefinancing maturing debt by issuing new debt securities. As discussed in Note 6, Leases of the Combined Notes to the Consolidated Financial Statements, FirstEnergy’s investments in capital trusts effectively reduce future lease obligations, also reducing interest rate risk.
Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income $89
 $100
 $110
 $76
 $23
 $2,008
 $2,406
 $2,456
Average interest rate 8.8% 8.9% 9.0% 9.5% 10.3% 5.4% 6.0%  
Liabilities:                
Long-term Debt:                
Fixed rate $751
 $964
 $866
 $1,330
 $891
 $11,628
 $16,430
 $18,585
Average interest rate 7.3% 5.9% 5.4% 4.7% 5.9% 6.2% 6.1%  
Variable rate 
 $150
 
 
 
 $585
 $735
 $735
Average interest rate   1.8%       0.1% 0.4%  
Equity Price Risk
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 provides a portion of non-contributory pre-retirement basic life insurance for employees who are eligible to retire. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.
The benefit plan assets and obligations are remeasured annually using a December 31 measurement date or as significant triggering events occur. As of December 31, 2011, the FirstEnergy pension plan was invested in approximately 19% of equity securities, 48% of fixed income securities, 21% of absolute return strategies, 6% of real estate, 2% of private equity and 4% of cash. A decline in the value of pension plan assets could result in additional funding requirements. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. During 2011, FirstEnergy made pre-tax contributions to its qualified pension plans of $372 million. FirstEnergy made an additional $600 million pre-tax contribution to the qualified pension plan on January 5, 2012.
NDT funds have been established to satisfy NGC’s and certain of the Utilities’ nuclear decommissioning obligations. As of December 31, 2011, approximately 79% of the funds were invested in fixed income securities, 12% of the funds were invested in equity


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securities and 9% were invested in short-term investments, with limitations related to concentration and investment grade ratings. The investments are carried at their market values of approximately $1,699 million, $258 million and $207 million for fixed income securities, equity securities and short-term investments, respectively, as of December 31, 2011, excluding ($52) million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $26 million reduction in fair value as of December 31, 2011. The decommissioning trusts of JCP&L, Met-Ed and Penelec are subject to regulatory accounting, basis differenceswith unrealized gains and taxlosses 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 recognized in earnings the unrealized losses on available-for-sale securities held in their NDT as OTTI. A decline in the value of FirstEnergy’s NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During 2011, approximately $1 million, $4 million and $1 million was contributed to the NDTs of JCP&L, OE and TE, respectively. FENOC has submitted a $95 million parental guarantee to the NRC for a short-fall in nuclear decommissioning funding to Beaver Valley Unit 1 and Perry.
CREDIT RISK
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. FirstEnergy evaluates the credit carryforward items are recognized atstanding of a prospective counterparty based on the statutory income tax ratesprospective counterparty's financial condition. FirstEnergy may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. FirstEnergy monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.
Wholesale Credit Risk
FirstEnergy measures wholesale credit risk as the replacement cost for derivatives in effectpower, natural gas, coal and emission allowances, adjusted for amounts owed to or due from counterparties for settled transactions. The replacement cost of open positions represents unrealized gains, net of any unrealized losses, where FirstEnergy has a legally enforceable right of set-off. FirstEnergy monitors and manages the credit risk of wholesale marketing, risk management and energy transacting operations through credit policies and procedures, which include an established credit approval process, daily monitoring of counterparty credit limits, the use of credit mitigation measures such as margin, collateral and the use of master netting agreements. FirstEnergy aggressively manages the quality of its portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB (S&P).
Retail Credit Risk
FirstEnergy is exposed to retail credit risk through competitive electricity activities, which serve residential, commercial and industrial companies. Retail credit risk results when customers default on contractual obligations or fail to pay for service rendered. This risk represents the loss that may be incurred due to the nonpayment of customer accounts receivable balances, as well as the loss from the resale of energy previously committed to serve customers.
Retail credit risk is managed through established credit approval policies, monitoring customer exposures and the use of credit mitigation measures such as deposits in the form of LOCs, cash or prepayment arrangements.
Retail credit quality is dependent on the economy and the ability of customers to manage through unfavorable economic cycles and other market changes. If the business environment were to be negatively affected by changes in economic or other market conditions, FirstEnergy's retail credit risk may be adversely impacted.
REGULATORY MATTERS
Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent amounts that are expected to be paid. Deferred taxcredited to customers through future regulated rates or amounts collected from customers for costs not yet incurred. FirstEnergy and the Utilities net their regulatory assets are recognizedand liabilities based on income tax ratesfederal and state jurisdictions.


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Net regulatory assets on FirstEnergy's and the Utility Registrants' Consolidated Balance Sheets are comprised of the following:
Regulatory Assets FirstEnergy OE CEI TE JCP&L Met-Ed Penelec
  (In millions)
December 31, 2011              
Regulatory transition costs $608
 $—
 $—
 $—
 $424
 $105
 $79
Customer receivables for future income taxes 508
 42
 1
 2
 29
 129
 145
Nuclear decommissioning, decontamination and spent fuel disposal costs (210) —
 —
 —
 (44) (99) (67)
Asset removal costs (240) (34) (60) (23) (147) —
 —
PJM transmission costs 340
 (3) (3) (1) —
 181
 63
Deferred generation costs 382
 125
 224
 37
 —
 (23) (11)
Distribution costs 267
 146
 73
 48
 —
 —
 —
Other 375
 87
 60
 7
 146
 36
 —
Total $2,030
 $363
 $295
 $70
 $408
 $329
 $209
December 31, 2010              
Regulatory transition costs $770
 $—
 $—
 $—
 $591
 $131
 $43
Customer receivables for future income taxes 328
 52
 2
 1
 30
 113
 130
Nuclear decommissioning, decontamination and spent fuel disposal costs (184) —
 —
 —
 (31) (92) (61)
Asset removal costs (237) (24) (47) (19) (147) —
 —
PJM transmission costs 183
 —
 —
 —
 —
 131
 52
Deferred generation costs 386
 125
 226
 35
 —
 —
 —
Distribution costs 426
 216
 155
 55
 —
 —
 —
Other 158
 34
 34
 1
 71
 13
 (1)
Total $1,830
 $403
 $370
 $73
 $514
 $296
 $163

Additionally, FirstEnergy had $381 million of net regulatory liabilities as of December 31, 2011, including $366 million of net regulatory liabilities attributable to Allegheny that are primarily related to asset removal costs. Net regulatory liabilities are classified within Other Noncurrent Liabilities on the Consolidated Balance Sheets.
Regulatory assets that do not earn a current return as of December 31, 2011 totaled approximately $413 million. Regulatory assets that do not earn a return are primarily comprised of certain regulatory transition and PJM transmission costs for Met-Ed and Penelec of $182 million and $115 million, respectively, that are expected to be recovered by 2020, and certain storm damage costs and pension and OPEB costs incurred by JCP&L of $122 million that are expected to be recovered by 2026.

RELIABILITY MATTERS

Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES, AE Supply, FGCO, FENOC, ATSI and TrAIL. The NERC is the ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including RFC. All of FirstEnergy's facilities are located within the RFC region. FirstEnergy actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by the RFC.

FirstEnergy believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such items are found, FirstEnergy develops information about the item and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an item to RFC. Moreover, it is clear that the NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with future new or amended standards cannot be determined at this time; however, 2005 amendments to the FPA provide that all prudent costs incurred to comply with the future reliability standards be recovered in rates. 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 that could have a material adverse effect on its financial condition, results of operations and cash flows.

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 resulting in customers losing power for up to eleven


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hours. 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. NERC has submitted first and second Requests for Information regarding this and another related matter. JCP&L is complying with these requests. JCP&L is not able to predict what actions, if any, the NERC may take with respect to this matter.

On August 23, 2010, FirstEnergy self-reported to RFC a vegetation encroachment event on a Met-Ed230kV line. This event did not result in a fault, outage, operation of protective equipment, or any other meaningful electric effect on any FirstEnergy transmission facilities or systems. On August 25, 2010, RFC issued a notice of enforcement to investigate the incident. FirstEnergy submitted a data response to RFC on September 27, 2010. On July 8, 2011, RFC and Met-Ed signed a settlement agreement to resolve all outstanding issues related to the vegetation encroachment event. The settlement calls for Met-Ed to pay a penalty of$650,000, and for FirstEnergy to perform certain mitigating actions. These mitigating actions include inspecting FirstEnergy's transmission system using LiDAR technology, and reporting the results of inspections, and any follow-up work, to RFC. FirstEnergy was performing the LiDAR work in response to certain other industry directives issued by NERC in 2010. NERC subsequently approved the settlement agreement and, on September 30, 2011, submitted the approved settlement to FERC for final approval. FERC approved the settlement agreement on October 28, 2011. Met-Ed subsequently paid the$650,000penalty and, on December 31, 2011, RFC sent written notice that this matter has been closed.

In 2011, RFC performed routine compliance audits of parts of FirstEnergy's bulk-power system and generally found the audited systems and process to be in full compliance with all audited reliability standards. RFC will perform additional audits in 2012.

MARYLAND
By statute enacted in 2007, the obligation of Maryland utilities to provide SOS to residential and small commercial customers, in exchange for recovery of their costs plus a reasonable profit, was extended indefinitely. The legislation also established a5-year cycle (to begin in 2008) for the MDPSC to report to the legislature on the status of SOS. PE now conducts rolling auctions to procure the power supply necessary to serve its customer load pursuant to a plan approved by the MDPSC. However, the terms on which PE will provide SOS to residential customers after the current settlement expires at the end of 2012 will depend on developments with respect to SOS in Maryland over the coming year, including but not limited to, possible MDPSC decisions in the proceedings discussed below.

The MDPSC opened a new docket in August 2007 to consider matters relating to possible “managed portfolio” approaches to SOS and other matters. “Phase II” of the case addressed utility purchases or construction of generation, bidding for procurement of demand response resources and possible alternatives if the TrAIL and PATH projects were delayed or defeated. It is unclear when the MDPSC will issue its findings in this proceeding.
In September 2009, the MDPSC opened a new proceeding to receive and consider proposals for construction of new generation resources in Maryland. In December 2009, Governor Martin O'Malley filed a letter in this proceeding in which he characterized the electricity market in Maryland as a “failure” and urged the MDPSC to use its existing authority to order the construction of new generation in Maryland, vary the means used by utilities to procure generation and include more renewables in the generation mix. In December 2010, the MDPSC issued an order soliciting comments on a model RFP for solicitation of long-term energy commitments by Maryland electric utilities. PE and numerous other parties filed comments, and on September 29, 2011, the MDPSC issued an order requiring the utilities to issue the RFP crafted by the MDPSC by October 7, 2011. The RFPs were issued by the utilities as ordered by the MDPSC. The order, as amended, indicated that bids were due by January 20, 2012, and that the MDPSC would be the entity evaluating all bids. The Chairman of the MDPSC has stated publicly that several bids were received, but no other information was released. After receipt of further comments from interested parties, including PE, on January 13, 2012, a hearing on whether more generation is needed, irrespective of what bids may have been received, was held on January 31, 2012. There has been no further action on this matter.

In September 2007, the MDPSC issued an order that required the Maryland utilities to file detailed plans for how they will meet the “EmPOWER Maryland” proposal that electric consumption be reduced by10%and electricity demand be reduced by15%, in each case by 2015.

The Maryland legislature in 2008 adopted a statute codifying the EmPOWER Maryland goals. In 2008, PE filed its comprehensive plans for attempting to achieve those goals, asking the MDPSC to approve programs for residential, commercial, industrial, and governmental customers, as well as a customer education program. The MDPSC ultimately approved the programs in August 2009 after certain modifications had been made as required by the MDPSC, and approved cost recovery for the programs in October 2009. Expenditures were estimated to be approximately$101 millionfor the PE programs for the period of 2009 to 2015 and would be recovered over thatsixyear period. Meanwhile, after extensive meetings with the MDPSC Staff and other stakeholders, PE's plans for additional and improved programs for the period 2012-2014 were filed on August 31, 2011. The MDPSC held hearings on PE's and the other utilities' plans in October 2011, and on December 22, 2011, issued an order approving Potomac Edison's plan with various modifications and follow-up assignments. On January 23, 2012, PE filed a Request for Rehearing because additional facts not considered by the MDPSC demonstrate, among other things, that conservation voltage reduction program expenditures should be accorded cost recovery through the EmPOWER surcharge, as has been provided for all other EmPOWER programs as opposed to recovery of those expenditures being addressed in a future base rate case as the MDPSC found in its order.


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In March 2009, the MDPSC issued an order temporarily suspending the right of all electric and gas utilities in the state to terminate service to residential customers for non-payment of bills. The MDPSC subsequently issued an order making various rule changes relating to terminations, payment plans, and customer deposits that make it more difficult for Maryland utilities to collect deposits or to terminate service for non-payment. The MDPSC is continuing to collect data on payment plan and related issues and has adopted regulations that expand the summer and winter “severe weather” termination moratoria when temperatures are very high or very low, fromoneday, as provided by statute, tothreedays on each occurrence.
The Maryland legislature passed a bill on April 11, 2011, which requires the MDPSC to promulgate rules by July 1, 2012 that address service interruptions, downed wire response, customer communication, vegetation management, equipment inspection, and annual reporting. In crafting the regulations, the legislation directs the MDPSC to consider cost-effectiveness, and provides that the MDPSC may adopt different standards for different utilities based on such factors as system design and existing infrastructure, geography, and customer density. Beginning in July 2013, the MDPSC is required to assess each utility's compliance with the new rules, and may assess penalties of up to$25,000per day per violation. The MDPSC convened a working group of utilities, regulators, and other interested stakeholders to address the topics of the proposed rules. A draft of the rules was filed, along with the report of the working group, on October 27, 2011. Hearings to consider the rules and comments occurred over four days between December 8 and 15, 2011, after which revised rules were sent for legislative review. The proposed rules were published in the Maryland Register on February 24, 2012, and a deadline of March 26, 2012, was set for the filing of further comments. A further hearing is required before the rules could become final. Separately, on July 7, 2011, the MDPSC adopted draft rules requiring monitoring and inspections for contact voltage. The draft rules were published in September, 2011. After a further hearing in October, 2011, the final rules were re-published and became effective on November 28, 2011.

NEW JERSEY

On September 8, 2011, the Division of Rate Counsel filed a Petition with the NJBPU asserting that it has reason to believe that JCP&L is earning an unreasonable return on its New Jersey jurisdictional rate base. The Division of Rate Counsel requests that the NJBPU order JCP&L to file a base rate case petition so that the NJBPU may determine whether JCP&L's current rates for electric service are just and reasonable. JCP&L filed an answer to the Petition on September 28, 2011, stating, inter alia, that the Division of Rate Counsel analysis upon which it premises its Petition contains errors and inaccuracies, that JCP&L's achieved return on equity is currently within a reasonable range, and that there is no reason for the NJBPU to require JCP&L to file a base rate case at this time.On November 30, 2011, the NJBPU ordered that the matter be assigned to the NJBPU President to act as presiding officer to set and modify the schedule for this matter as appropriate, decide upon motions, and otherwise control the conduct of this case, without the need for full Board approval. The matter is pending and a schedule for further proceedings has not yet been established.

On September 22, 2011, the NJBPU ordered that JCP&L hire a Special Reliability Master, subject to NJBPU approval, to evaluate JCP&L's design, operating, maintenance and performance standards as they pertain to the Morristown, New Jersey underground electric distribution system, and make recommendations to JCP&L and the NJBPU on the appropriate courses of action necessary to ensure adequate reliability and safety in the Morristown underground network.On October 12, 2011, the Special Reliability Master was selected and on January 31, 2012, the project report was submitted to the Company and NJBPU Staff. On February 10, 2012, the NJBPU accepted the report and directed the Staff to present recommendations on March 12, 2012, on actions required by JCP&L to ensure the safe, reliable operation of the Morristown network.

Pursuant to a formal Notice issued by the NJBPU on September 14, 2011, public hearings were held on September 26 and 27, 2011, to solicit public comments regarding the state of preparedness and responsiveness of the local electric distribution companies prior to, during and after Hurricane Irene. By subsequent Notice issued September 28, 2011, additional hearings were held in October 2011. Additionally, the NJBPU accepted written comments through October 31, 2011 related to this inquiry.On December 4, 2011, the NJBPU Division of Reliability and Security issued a Request for Qualifications soliciting bid proposals from qualified consulting firms to provide expertise in the review and evaluation of New Jersey's electric distribution companies' preparation and restoration to Hurricane Irene and the October 2011 snowstorm. Responsive bids were submitted on January 20, 2012, and the report of selected bidder is to be submitted to the NJPBU 120 days from the date the contract is awarded. On December 14, 2011, the NJBPU Staff filed a report of its preliminary findings and recommendations with respect to the electric utility companies' planning and response to Hurricane Irene and the October 2011 snowstorm. The NJBPU has not indicated what additional action, if any, may be taken as a result of information obtained through this process.

OHIO

The Ohio Companies operate under an ESP, which expires on May 31, 2014. The material terms of the ESP include: generation supplied through a CBP commencing June 1, 2011; a load cap of no less than80%, which also applies to tranches assigned post-auction; a6%generation discount to certain low income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (FES is one of the wholesale suppliers to the Ohio Companies); no increase in base distribution rates through May 31, 2014; and a new distribution rider, Rider DCR, to recover a return of, and on, capital investments in the delivery system. The Ohio Companies also agreed not to recover from retail customers certain costs related to transmission cost allocations by PJM as a result of ATSI's integration into PJM for the longer of the five-year period from June 1, 2011 through May 31, 2015 or when the amount of costs avoided by customers for certain types of products totals$360 milliondependent on the outcome of certain PJM proceedings, agreed to establish a$12 millionfund to assist low income customers over the term of the ESP and agreed to


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additional matters related to energy efficiency and alternative energy requirements.

Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total annual energy savings equivalent to approximately166,000MWH in 2009,290,000MWH in 2010,410,000MWH in 2011,470,000MWH in 2012 and530,000MWH in 2013, with additional savings required through 2025. Utilities were also required to reduce peak demand in 2009 by1%, with an additional0.75%reduction each year thereafter through 2018.

In December 2009, the Ohio Companies filed the requiredthreeyear 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. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers in 2012. The PUCO issued an Opinion and Order generally approving the Ohio Companies'three-year plan, and the Ohio Companies are in the process of implementing those programs included in the Plan. OE fell short of its statutory 2010 energy efficiency and peak demand reduction benchmarks and therefore, on January 11, 2011, it requested that its 2010 energy efficiency and peak demand reduction benchmarks be amended to actual levels achieved in 2010. Moreover, because the PUCO indicated, when approving the 2009 benchmark request, that it would modify the Ohio Companies' 2010 (and 2011 and 2012) energy efficiency benchmarks when addressing the portfolio plan, the Ohio Companies were not certain of their 2010 energy efficiency obligations. Therefore, CEI and TE (each of which achieved its 2010 energy efficiency and peak demand reduction statutory benchmarks) also requested an amendment if and only to the degree one was deemed necessary to bring them into compliance with their yet-to-be-defined modified benchmarks. On May 19, 2011, the PUCO granted the request to reduce the 2010 energy efficiency and peak demand reductions to the level achieved in 2010 for OE, while finding that the motion was moot for CEI and TE. On June 2, 2011, the Ohio Companies filed an application for rehearing to clarify the decision related to CEI and TE. On July 27, 2011, the PUCO denied that application for rehearing, but clarified that CEI and TE could apply for an amendment in the future for the 2010 benchmarks should it be necessary to do so. Failure to comply with the benchmarks or to obtain such an amendment may subject the Ohio Companies to an assessment of a penalty by the PUCO. In addition to approving the programs included in the plan, with only minor modifications, the PUCO authorized the Ohio Companies to recover all costs related to the original CFL program that the Ohio Companies had previously suspended at the request of the PUCO. Applications for Rehearing were filed by the Ohio Companies, Ohio Energy Group and Nucor Steel Marion, Inc. on April 22, 2011, regarding portions of the PUCO's decision, including the method for calculating savings and certain changes made by the PUCO to specific programs. On September 7, 2011, the PUCO denied those applications for rehearing. The PUCO also included a new standard for compliance with the statutory energy efficiency benchmarks by requiring electric distribution companies to offer “all available cost effective energy efficiency opportunities” regardless of their level of compliance with the benchmarks as set forth in the statute.On October 7, 2011, the Ohio Companies, the Industrial Energy Users - Ohio, and the Ohio Energy Group filed applications for rehearing, arguing that the PUCO'S new standard is unlawful. The Ohio Companies also asked the PUCO to withdraw its amendment of CEI's and TE's 2010 energy efficiency benchmarks. The PUCO did not rule on the Applications for Rehearing within thirty days, thus denying them by operation of law. On December 30, 2011, the Ohio Companies filed a notice of appeal with the Supreme Court of Ohio, challenging the PUCO's new standard. No procedural schedule has been established.

Additionally, under SB221, electric utilities and electric service companies are required to serve part of their load in 2011 from renewable energy resources equivalent to1.00%of the average of the KWH they served in 2008-2010; in 2012 from renewable energy resources equivalent to1.50%of the average of the KWH they served in 2009-2011; and in 2013 from renewable energy resources equivalent to2.00%of the average of the KWH they served in 2010-2012. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RECs acquired through thesetwoRFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. In March 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market and reduced the Ohio Companies' aggregate 2009 benchmark to the level of SRECs the Ohio Companies acquired through their 2009 RFP processes, provided the Ohio Companies' 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC benchmark. On April 15, 2011, the Ohio Companies filed an application seeking an amendment to each of their 2010 alternative energy requirements for solar RECs generated in Ohio on the basis that an insufficient quantity of solar resources are available in the market but reflecting solar RECs that they have obtained and providing additional information regarding efforts to secure solar RECs. On August 3, 2011, the PUCO granted the Ohio Companies' force majeure request for 2010 and increased their 2011 benchmark by the amount of SRECs generated in Ohio that the Ohio Companies were short in 2010. On September 2, 2011, the Environmental Law and Policy Center and Nucor Steel Marion, Inc. filed applications for rehearing. The Ohio Companies filed their response on September 12, 2011. These applications for rehearing were denied by the PUCO on September 20, 2011, but as part of its Entry on Rehearing the PUCO opened a new docket to review the Ohio Companies' alternative energy recovery rider. Separately,oneparty has filed a request that the PUCO audit the cost of the Ohio Companies' compliance with the alternative energy requirements and the Ohio Companies' compliance with Ohio law. The PUCO selected auditors to perform a financial and a management audit, and final audit reports are to be filed with the PUCO by May 15, 2012. In August 2011, the Ohio Companies conducted two RFP processes to obtain RECs to meet the statutory benchmarks for 2011 and beyond.

PENNSYLVANIA
The PPUC entered an Order on March 3, 2010 that denied the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, directed Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructed Met-Ed and Penelec to work with the various intervening parties to file a recommendation to the PPUC regarding the establishment of a separate account for all marginal transmission losses


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collected from customers plus interest to be used to mitigate future generation rate increases beginning January 1, 2011. In March 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 to end collection of costs for marginal transmission losses. The PPUC granted the requested stay until December 31, 2010. Pursuant to the PPUC's order, Met-Ed and Penelec filed plans to establish separate accounts for marginal transmission loss revenues and related interest and carrying charges. Pursuant to the plan approved by the PPUC, Met-Ed and Penelec began to refund those amounts to customers in January 2011, and the refunds are continuing over a 29 month period until the full amounts previously recovered for marginal transmission loses are refunded. In April 2010, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania appealing the PPUC's March 3, 2010 Order. On June 14, 2011, the Commonwealth Court issued an opinion and order affirming the PPUC's Order to the extent that it holds that line loss costs are not transmission costs and, therefore, the approximately$254 millionin marginal transmission losses and associated carrying charges for the period prior to January 1, 2011, are not recoverable under Met-Ed's and Penelec's TSC riders. Met-Ed and Penelec filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court and also a complaint seeking relief in the U.S. District Court for the Eastern District of Pennsylvania, which was subsequently amended. The PPUC filed a Motion to Dismiss Met-Ed's and Penelec's Amended Complaint on September 15, 2011. Met-Ed and Penelec filed a Responsive brief in Opposition to the PPUC's Motion to Dismiss on October 11, 2011. Although the ultimate outcome of this matter cannot be determined at this time, Met-Ed and Penelec believe that they should ultimately prevail through the judicial process and therefore expect to fully recover the approximately$254 million($189 millionfor Met-Ed and$65 millionfor Penelec) in marginal transmission losses for the period prior to January 1, 2011.

In each of May 2008, 2009 and 2010, the PPUC approved Met-Ed's and Penelec's annual updates to their TSC rider for the annual periods between June 1, 2008 to 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 PPUC's approval in May 2010 authorized an increase to the TSC for Met-Ed's customers to provide for full recovery by December 31, 2010.

In February 2010, Penn filed a Petition for Approval of its DSP for the period June 1, 2011 through May 31, 2013. In July 2010, the parties to the proceeding filed a Joint Petition for Settlement of all issues. Although the PPUC's Order approving the Joint Petition held that the provisions relating to the recovery of MISO exit fees and one-time PJM integration costs (resulting from Penn's June 1, 2011 exit from MISO and integration into PJM) were approved, it made such provisions subject to the approval of cost recovery by FERC. Therefore, Penn may not put these provisions into effect until FERC has approved the recovery and allocation of MISO exit fees and PJM integration costs.

Pennsylvania adopted Act 129 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, (EE&C Plan), by July 1, 2009, setting forth the utilities' plans to reduce energy consumption by a minimum of1%and3%by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of4.5%by May 31, 2013. Act 129 provides for potentially significant financial penalties to be assessed upon utilities that fail to achieve the required reductions in consumption and peak demand. Act 129 also required utilities to file a SMIP with the PPUC.

The PPUC entered an Order in February 2010 giving final approval to all aspects of the EE&C Plans of Met-Ed, Penelec and Penn and the tariff rider became effective March 1, 2010. On February 18, 2011, the companies filed a petition to approve their First Amended EE&C Plans. On June 28, 2011, a hearing on the petition was held before an ALJ.On December 15, 2011, the ALJ recommended that the amended plans be approved as proposed, and on January 12, 2012, the Commission approved the plans.
WP filed its original EE&C Plan in June 2009, which the PPUC approved, in large part, by Opinion and Order entered in October 2009. In September 2010, WP filed an amended EE&C Plan that is less reliant on smart meter deployment, which the PPUC approved in January 2011.
On August 9, 2011, WP filed a petition to approve its Second Amended EE&C Plan. The proposed Second Revised Plan includes measures and a new program and implementation strategies consistent with the successful EE&C programs of Met-Ed, Penelec and Penn that are designed to enable WP to achieve the post-2011 Act 129 EE&C requirements.On January 6, 2012, a Joint Petition for Settlement of all issues was filed by the parties to the proceeding.

The Pennsylvania Companies submitted a preliminary report on July 15, 2011, and a final report on November 15, 2011, in which they reported on their compliance with statutory May 31, 2011, energy efficiency benchmarks.Met-Ed, Penelec and Penn achieved the 2011 benchmarks; however WP has been unable to provide final results because several customers are still accumulating necessary documentation for projects that may qualify for inclusion in the final results. Preliminary numbers indicate that WP did not achieve its 2011 benchmark and it is not known at this time whether WP will be subject to a fine for failure to achieve the benchmark. WP is unable to predict the outcome of this matter or estimate any possible loss or range of loss.

In December 2009, WP filed a motion to reopen the evidentiary record to submit an alternative smart meter plan proposing, among other things, a less-rapid deployment of smart meters.

In light of the significant expenditures that would be associated with its smart meter deployment plans and related infrastructure upgrades, as well as its evaluation of recent PPUC decisions approving less-rapid deployment proposals by other utilities, WP re-


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evaluated its Act 129 compliance strategy, including both its plans with respect to smart meter deployment and certain smart meter dependent aspects of the EE&C Plan. In October 2010, WP and Pennsylvania's OCA filed a Joint Petition for Settlement addressing WP's smart meter implementation plan with the PPUC. Under the terms of the proposed settlement, WP proposed to decelerate its previously contemplated smart meter deployment schedule and to target the installation of approximately25,000smart meters in support of its EE&C Plan, based on customer requests, by mid-2012. The proposed settlement also contemplates that WP take advantage of the30-month grace period authorized by the PPUC to continue WP's efforts to re-evaluate full-scale smart meter deployment plans. WP currently anticipates filing its plan for full-scale deployment of smart meters in June 2012. Under the terms of the proposed settlement, WP would be permitted to recover certain previously incurred and anticipated smart-meter related expenditures through a levelized customer surcharge, with certain expenditures amortized over a ten-year period. Additionally, WP would be permitted to seek recovery of certain other costs as part of its revised SMIP that it currently intends to file in June 2012, or in a future base distribution rate case.
Following additional proceedings, on March 9, 2011, WP submitted an Amended Joint Petition for Settlement which restates the Joint Petition for Settlement filed in October 2010, adds the PPUC's Office of Trial Staff as a signatory party, and confirms the support or non-opposition of all parties to the settlement.Oneparty retained the ability to challenge the recovery of amounts spent on WP's original smart meter implementation plan. A Joint Stipulation with the OSBA was also filed on March 9, 2011. The PPUC approved the Amended Joint Petition for Full Settlement by order entered June 30, 2011.

By Tentative Order entered in September 2009, the PPUC provided for an additional30-day comment period on whether the 1998 Restructuring Settlement, which addressed how Met-Ed and Penelec were going to implement direct access to a competitive market for the generation of electricity, allows Met-Ed and Penelec to apply over-collection of NUG costs for select and isolated months to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists. In response to the Tentative Order, various parties filed comments objecting to the accounting method utilized by Met-Ed and Penelec.On January 30, 2012, the Commission entered a final order approving Met-Ed's and Penelec's accounting methodology whereby NUG over-collection revenue may be used to reduce non-NUG stranded costs, even if a cumulative NUG stranded cost balance exists.

In the PPUC Order approving the FirstEnergy and Allegheny merger, the PPUC announced that a separate statewide investigation into Pennsylvania's retail electricity market will be conducted with the goal of making recommendations for improvements to ensure that a properly functioning and workable competitive retail electricity market exists in the state. On April 29, 2011, the PPUC entered an Order initiating the investigation and requesting comments from interested parties on eleven directed questions concerning retail markets in Pennsylvania. Met-Ed, Penelec, Penn Power and WP submitted joint comments on June 3, 2011. FES also submitted comments on June 3, 2011. On June 8, 2011, the PPUC conducted an en banc hearing on these issues at which both the Pennsylvania Companies and FES participated and offered testimony.A technical conference was held on August 10, 2011, and a second en banc was held on November 10, 2011, to discuss intermediate steps that can be taken to promote the development of a competitive market. Teleconferences are scheduled through March 2012, with another en banc hearing to be held on March 21, 2012, to explore the future of default service in Pennsylvania following the expiration of the upcoming default service plans on May 31, 2015. Following the issuance of a Tentative Order and comments filed by numerous parties, the Commission entered a final order on December 16, 2011, providing recommendations for components to be included in upcoming default service plans. An intermediate work plan was also presented on December 16, 2011, by Tentative Order, on which initial comments were submitted by Met-Ed, Penelec, Penn and WP on January 17, 2012. FES also submitted comments. Reply comments were submitted on February 1, 2012. It is expected that a final order implementing the intermediate work plan and a long range plan will be presented by the PPUC, both in March 2012.

The PPUC issued a Proposed Rulemaking Order on August 25, 2011, which proposed a number of substantial modifications to the current Code of Conduct regulations that were promulgated to provide competitive safeguards to the competitive retail electric market in Pennsylvania. The proposed changes include, but are not limited to: an EGS may not have the same or substantially similar name as the EDC or its corporate parent; EDCs and EGSs would not be permitted to share office space and would need to occupy different buildings; EDCs and affiliated EGSs could not share employees or services, except certain corporate support, emergency, or tariff services (the definition of "corporate support services" excludes items such as information systems, electronic data interchange, strategic management and planning, regulatory services, legal services, or commodities that have been included in regulated rates at less than market value); and an EGS must enter into a trademark agreement with the EDC before using its trademark or service mark. The Proposed Rulemaking Order, which was published on February 11, 2012, calls for comments to be submitted by March 27, 2012. If implemented these rules could require a significant change in the way FES, Met-Ed, Penelec, Penn and WP do business in Pennsylvania, and could possibly have an adverse impact on their results of operations and financial condition.

In November 2011, Met-Ed, Penelec, Penn and WP filed a Joint Petition for Approval of their Default Service Plan for the period June 1, 2013 through May 31, 2015. The Pennsylvania Companies' direct case was submitted in its entirety on December 20, 2011. Evidentiary hearings are scheduled for April 11-13, 2012, and a final order must be entered by the PPUC by August 17, 2012.

WEST VIRGINIA
In 2009, the West Virginia Legislature enacted the AREPA, which generally requires that a specified minimum percentage of electricity sold to retail customers in West Virginia by electric utilities each year be derived from alternative and renewable energy resources according to a predetermined schedule of increasing percentage targets, including10%by 2015,15%by 2020, and25%by 2025.


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In November 2010, the WVPSC issued RPS Rules, which became effective on January 4, 2011. Under the RPS Rules, on or before January 1, 2011, each electric utility subject to the provisions of this rule was required to prepare an alternative and renewable energy portfolio standard compliance plan and file an application with the WVPSC seeking approval of such plan. MP and PE filed their combined compliance plan in December 2010. A hearing was held at the WVPSC on June 13, 2011. An order was issued by the WVPSC in September 2011, which conditionally approved MP's and PE's compliance plan, contingent on the outcome of the resource credits case discussed below.

Additionally, in January 2011, MP and PE filed an application with the WVPSC seeking to certify three facilities as Qualified Energy Resource Facilities. The application was approved and the three facilities are capable of generating renewable credits which will assist the companies in meeting their combined requirements under the AREPA. An annual update filing is due on March 31, 2012. Further, in February 2011, MP and PE filed a petition with the WVPSC seeking an Order declaring that MP is entitled to all alternative and renewable energy resource credits associated with the electric energy, or energy and capacity, that MP is required to purchase pursuant to electric energy purchase agreements between MP and three non-utility electric generating facilities in West Virginia. The City of New Martinsville and Morgantown Energy Associates, each the owner of one of the contracted resources, has participated in the case in opposition to the Petition. A hearing was held at the WVPSC on August 25 and 26, 2011.On November 22, 2011, the WVPSC issued an order granting ownership of all RECs produced by the facilities to MP. On December 22, 2011, the WVPSC order was appealed, and the order was stayed pending the outcome of the appeal. MP's brief was filed on February 13, 2012. Should MP be unsuccessful in the appeal, it will have to procure the requisite RECs to comply with AREPA from other sources. MP expects to recover such costs from customers.

In September 2011, MP and PE filed with the WVPSC to recover costs associated with fuel and purchased power (the ENEC) in the amount of$32 millionwhich represents an approximate3%overall increase in such costs over the past two years, primarily attributable to rising coal prices. The requested increase was partially offset by$2.5 millionof synergy savings directly resulting from the merger of FirstEnergy and AE, which closed in February 2011. Under a cost recovery clause established by the WVPSC in 2007, MP and PE customer bills are adjusted periodically to reflect upward or downward changes in the cost of fuel and purchased power. The utilities' most recent request to recover costs for fuel and purchased power was in September 2009.MP and PE entered into a Settlement Agreement related to this matter. The WVPSC issued an order on December 30, 2011, approving the settlement agreement. The approved settlement resulted in an increase of$19.6 million, instead of the requested$32 million, with additional costs to be recovered over time with a carrying charge.

FERC MATTERS

PJM Transmission Rate

In April 2007, FERC issued 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, FERC directed that costs for new transmission facilities that are rated at500kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate based on the amount of load served in a transmission zone. Costs for new transmission facilities that are rated at less than500kV, however, are to be allocated on a load flow methodology, which is generally referred to as a “beneficiary pays” approach to allocating the cost of high voltage transmission facilities.

FERC's Opinion 494 order was appealed to the U.S. Court of Appeals for the Seventh Circuit, which issued a decision in August 2009. The court affirmed FERC's ratemaking treatment for existing transmission facilities, but found that FERC had not supported its decision to allocate costs for new500kV and higher voltage facilities on a load ratio share basis and, based on this finding, remanded the rate design issue to FERC.

In an order dated January 21, 2010, FERC set the matter for a “paper hearing” and requested parties to submit written comments pursuant to the schedule described in the order. FERC identifiednineseparate issues for comments and directed PJM to file the first round of comments on February 22, 2010, with other parties submitting responsive comments and then reply comments on later dates. PJM filed certain studies with FERC on April 13, 2010, in response to the FERC order. PJM's filing demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain load serving entities in PJM bearing the majority of the 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. Other utilities and state commissions supported continued socialization of these costs on a load ratio share basis. This matter is awaiting action by FERC. FirstEnergy cannot predict the outcome of this matter or estimate the possible loss or range of loss.

RTO Realignment

On June 1, 2011, ATSI and the ATSI zone entered into PJM. The move was performed as planned with no known operational or reliability issues for ATSI or for the wholesale transmission customers in the ATSI zone.

On February 1, 2011, ATSI in conjunction with PJM filed its proposal with FERC for moving its transmission rate into PJM's tariffs. On April 1, 2011, the MISO TOs (including ATSI) filed proposed tariff language that describes the mechanics of collecting and


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administering MTEP costs from ATSI-zone ratepayers. From March 20, 2011 through April 1, 2011, FirstEnergy, PJM and the MISO submitted numerous filings for the purpose of effecting movement of the ATSI zone to PJM on June 1, 2011. These filings include amendments to the MISO's tariffs (to remove the ATSI zone), submission of load and generation interconnection agreements to reflect the move into PJM, and submission of changes to PJM's tariffs to support the move into PJM.

On May 31, 2011, FERC issued orders that address the proposed ATSI transmission rate, and certain parts of the MISO tariffs that reflect the mechanics of transmission cost allocation and collection. In its May 31, 2011 orders, FERC approved ATSI's proposal to move the ATSI formula rate into the PJM tariff without significant change. Speaking to ATSI's proposed treatment of the MISO's exit fees and charges for transmission costs that were allocated to the ATSI zone, FERC required ATSI to present a cost-benefit study that demonstrates that the benefits of the move for transmission customers exceed the costs of any such move, which FERC had not previously required. Accordingly, FERC ruled that these costs must be removed from ATSI's proposed transmission rates until such time as ATSI files and FERC approves the cost-benefit study. On June 30, 2011, ATSI submitted the compliance filing that removed the MISO exit fees and transmission cost allocation charges from ATSI's proposed transmission rates. Also on June 30, 2011, ATSI requested rehearing of FERC's decision to require a cost-benefit analysis as part of FERC's evaluation of ATSI's proposed transmission rates. Finally, and also on June 30, 2011, the MISO and the MISO TOs filed a competing compliance filing - one that would require ATSI to pay certain charges related to construction and operation of transmission projects within the MISO even though FERC ruled that ATSI cannot pass these costs on to ATSI's customers. ATSI on the one hand, and the MISO and MISO TOs on the other, have submitted subsequent filings - each of which is intended to refute the other's claims. ATSI's compliance filing and request for rehearing, as well as the pleadings that reflect the dispute between ATSI and the MISO/MISO TOs, are currently pending before FERC.

From late April 2011 through June 2011, FERC issued other orders that address ATSI's move into PJM. Also, ATSI and the MISO were able to negotiate an agreement of ATSI's responsibility for certain charges associated with long term firm transmission rights that, according to the MISO, were payable by the ATSI zone upon its departure from the MISO. ATSI did not and does not agree that these costs should be charged to ATSI but, in order to settle the case and all claims associated with the case, ATSI agreed to a one-time payment of$1.8 millionto the MISO. This settlement agreement has been submitted for FERC's review and approval. The final outcome of those proceedings that address the remaining open issues related to ATSI's move into PJM and their impact, if any, on FirstEnergy cannot be predicted at this time.

MISO Multi-Value Project Rule Proposal

In July 2010, MISO and certain MISO transmission owners jointly filed with FERC their proposed cost allocation methodology for certain new transmission projects. The new transmission projects--described as MVPs - are a class of transmission projects that are approved via the MTEP. The filing parties proposed to allocate the costs of MVPs by means of a usage-based charge that will be applied to all loads within the MISO footprint, and to energy transactions that call for power to be “wheeled through” the MISO as well as to energy transactions that “source” in the MISO but “sink” outside of MISO. The filing parties expect that the MVP proposal will fund the costs of large transmission projects designed to bring wind generation from the upper Midwest to load centers in the east. The filing parties requested an effective date for the proposal of July 16, 2011. On August 19, 2010, MISO's Board approved the first MVP project -- the “Michigan Thumb Project.” Under MISO's proposal, the costs of MVP projects approved by MISO's Board prior to the June 1, 2011 effective date of FirstEnergy's integration into PJM would continue to be allocated to FirstEnergy. MISO estimated that approximately$15 millionin annual revenue requirements would be allocated to the ATSI zone associated with the Michigan Thumb Project upon its completion.

In September 2010, FirstEnergy filed a protest to the MVP proposal arguing that MISO's proposal to allocate costs of MVPs projects across the entire MISO footprint does not align with the established rule that cost allocation is to be based on cost causation (the “beneficiary pays” approach). FirstEnergy also argued that, in light of progress that had been made to date in the ATSI integration into PJM, it would be unjust and unreasonable to allocate any MVP costs to the ATSI zone, or to ATSI. Numerous other parties filed pleadings on MISO's MVP proposal.

In December 2010, FERC issued an order approving the MVP proposal without significant change. Despite being presented with the issue by FirstEnergy and the MISO, the FERC did not address clearly the question of whether the MVP costs would be payable by ATSI or load in the ATSI zone. FERC stated that the MISO's tariffs obligate ATSI to pay all charges that attached prior to ATSI's exit but ruled that the question of the amount of costs that are to be allocated to ATSI or to load in the ATSI zone were beyond the scope of FERC's order and would be addressed in future proceedings.

On January 18, 2011, FirstEnergy requested rehearing of FERC's order. In its rehearing request, FirstEnergy argued that because the MVP rate is usage-based, costs could not be applied to ATSI, which is a stand-alone transmission company that does not use the transmission system. FirstEnergy also renewed its arguments regarding cost causation and the impropriety of allocating costs to the ATSI zone or to ATSI.On October 21, 2011, FERC issued its order on rehearing, but that order did not address FirstEnergy's argument directly. FERC ruled instead that if ATSI was subject to MVP charges then ATSI owed these charges upon exit of the MISO. On October 31, 2011, FESC filed a Petition of Review for the FERC's December 2010 order and October 21, 2011 order on rehearing of that order with the U.S. Court of Appeals for the D.C. Circuit. Other parties also filed appeals of those orders and, in November, 2011, the cases were consolidated for briefing and disposition in the U.S. Court of Appeals for the Seventh Circuit. On January 27, 2012, the court ordered the FERC to file a proposed briefing format and schedule on or before March 20, 2012.



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On August 3, 2011, FirstEnergy filed a complaint with FERC based on the FERC's December 2010 order. In the complaint, FirstEnergy argued that ATSI perfected the legal and financial requirements necessary to exit MISO before any MVP responsibilities could attach and asked FERC to rule that MISO cannot charge ATSI for MVP costs. On September 2, 2011, MISO, its TOs and other parties, filed responsive pleadings. On September 19, 2011, ATSI filed an answer. On December 29, 2011, the MISO and the MISO TOs filed a new “Schedule 39” to the MISO's tariff. Schedule 39 purports to establish a process whereby the MISO would bill TOs for MVP costs that, according to the MISO, attached to the utility prior to such TOs withdrawal from the MISO. On January 19, 2012, FirstEnergy filed a protest to the MISO's new Schedule 39 tariff.

On February 27, 2012, FERC issued an order (February 2012 Order) dismissing ATSI's August 3, 2011 complaint. In the February 2012 Order, FERC accepted the MISO's Schedule 39 tariff, subject to hearings and potential refund of MVP charges to ATSI. The basis for any subsequent hearing is whether the Schedule 39 tariff was in effect when they are settled.at the time that ATSI exited the MISO. FirstEnergy is evaluating the February 2012 Order and will determine the next steps.

FirstEnergy cannot predict the outcome of these proceedings or estimate the possible loss or range of loss.

FirstEnergy accountsCompanies' PJM FTR Contract Underfunding Complaint

On December 28, 2011, FES and AE Supply filed a complaint with FERC against PJM challenging the ongoing underfunding of FTR contracts, which exist to hedge against transmission congestion in the day-ahead markets. The underfunding is a result of PJM's practice of using the funds that are intended to pay the holders of FTR contracts to pay instead for uncertaintycongestion costs that occur in income taxes recognizedthe real time markets. Underfunding of the FTR contracts resulted in losses of approximately$35 millionto FES and AE Supply in the 2010-2011 Delivery Year. To date, losses for the 2011-2012 Delivery Year are estimated to be approximately$6 million.

On January 13, 2012, PJM filed comments that describe changes to the PJM tariff that, if adopted, should remedy the underfunding issue. Many parties also filed comments supporting FES' and AE Supply's position. Other parties, generally representatives of end-use customers who will have to pay the charges, filed in opposition to the complaint. The matter is currently pending before FERC. FirstEnergy cannot predict the outcome of this matter or estimate the possible loss or range of loss.

California Claims Matters

In October 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the CDWR during 2001. The settlement proposal claims that CDWR is owed approximately$190 millionfor these alleged overcharges. This proposal was made in the context of mediation efforts by FERC and the United States Court of Appeals for the Ninth Circuit in pending proceedings to resolve all outstanding refund and other claims, including claims of alleged price manipulation in the California energy markets during 2000 and 2001. The Ninth Circuit has since remandedoneof those proceedings to FERC, which arises out of claims previously filed with FERC by the California Attorney General on behalf of certain California parties against various sellers in the California wholesale power market, including AE Supply (the Lockyer case). AE Supply and several other sellers filed motions to dismiss the Lockyer case. In March 2010, the judge assigned to the case entered an opinion that granted the motions to dismiss filed by AE Supply and other sellers and dismissed the claims of the California Parties. On May 4, 2011, FERC affirmed the judge's ruling. On June 3, 2011, the California parties requested rehearing of the May 4, 2011 order. The request for rehearing remains pending.

In June 2009, the California Attorney General, on behalf of certain California parties, filed a second complaint with FERC against various sellers, including AE Supply (the Brown case), again seeking refunds for trades in the California energy markets during 2000 and 2001. The above-noted trades with CDWR are the basis for including AE Supply in this new complaint. AE Supply filed a motion to dismiss the Brown complaint that was granted by FERC on May 24, 2011. On June 23, 2011, the California Attorney General requested rehearing of the May 24, 2011 order. That request for rehearing also remains pending. FirstEnergy cannot predict the outcome of either of the above matters or estimate the possible loss or range of loss.

PATH Transmission Project

The PATH Project is comprised of a765kV transmission line that was proposed to extend from West Virginia through Virginia and into Maryland, modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland.

PJM initially authorized construction of the PATH Project in June 2007. In December 2010, PJM advised that its 2011 Load Forecast Report included load projections that are different from previous forecasts and that may have an impact on the proposed in-service date for the PATH Project. As part of its 2011 RTEP, and in response to a January 19, 2011, directive by a Virginia Hearing Examiner, PJM conducted a series of analyses using the most current economic forecasts and demand response commitments, as well as potential new generation resources. Preliminary analysis revealed the expected reliability violations that necessitated the PATH Project had moved several years into the future. Based on those results, PJM announced on February 28, 2011, that its Board of Managers had decided to hold the PATH Project in abeyance in its financial statements. We account2011 RTEP and directed FirstEnergy and AEP, as the sponsoring transmission owners, to suspend current development efforts on the project, subject to those activities necessary to maintain the project in its current state, while PJM conducts more rigorous analysis of the need for uncertain income tax positionsthe project as part of its continuing RTEP


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process. PJM stated that its action did not constitute a directive to FirstEnergy and AEP to cancel or abandon the PATH Project. PJM further stated that it will complete a more rigorous analysis of the PATH Project and other transmission requirements and its Board will review this comprehensive analysis as part of its consideration of the 2011 RTEP. On February 28, 2011, affiliates of FirstEnergy and AEP filed motions or notices to withdraw applications for authorization to construct the project that were pending before state commissions in West Virginia, Virginia and Maryland. Withdrawal was deemed effective upon filing the notice with the MDPSC. The WVPSC and VSCC have granted the motions to withdraw.

PATH submitted a filing to FERC to implement a formula rate tariff effective March 1, 2008. In a November 19, 2010 order addressing various matters relating to the formula rate, FERC set the project's base ROE for hearing and reaffirmed its prior authorization of a return on CWIP, recovery of start-up costs and recovery of abandonment costs. In the order, FERC also granted a1.5%ROE incentive adder and a0.5%ROE adder for RTO participation. These adders will be applied to the base ROE determined as a result of the hearing. The PATH Companies, Joint Intervenors, Joint Consumer Advocates and FERC staff have agreed to a four year moratorium. A settlement was reached, which reflects a base ROE of10.4%(plus authorized adders) effective January 1, 2011. Accordingly, the revised ROE was reflected in a revised Projected Transmission Revenue Requirement for 2011 with true-up occurring in 2013. The FirstEnergy portion of the refund for March 1, 2008, through December 31, 2010, is approximately$2 million(inclusive of interest). The refund amount was computed using a benefit recognition modelbase ROE of10.8%plus authorized adders. On October 7, 2011, PATH and six intervenors submitted to FERC an unopposed settlement agreement. Contemporaneous with this submission, PATH and the six intervenors filed with the Chief ALJ of FERC a joint motion for interim approval and authorization to implement the refund on an interim basis pending issuance of a FERC order acting on the settlement agreement. On October 12, 2011, the motion for interim approval and authorization to implement the refund was granted by the Chief ALJ. On February 16, 2012, FERC approved the settlement agreement and dismissed as moot, in light of its approval of the settlement, PATH's pending request for rehearing of the November 19, 2010 order.

Yards Creek
The Yards Creek Pumped Storage Project is a400MW hydroelectric project located in Warren County, New Jersey. JCP&L owns an undivided50%interest in the project, and operates the project. PSEG Fossil, LLC, a subsidiary of Public Service Enterprise Group, owns the remaining interest in the plant. The project was constructed in the early 1960s, and became operational in 1965. Authorization to operate the project is by a license issued by the FERC. The existing license expires on February 28, 2013.

In February 2011, JCP&L and PSEG filed a joint application with FERC to renew the license for an additional forty years. The companies are pursuing relicensure through FERC's ILP. Under the ILP, FERC will assess the license applications, issue draft and final Environmental Assessments/Environmental Impact Studies (as required by NEPA), and provide opportunities for intervention and protests by affected third parties. FERC may hold hearings during the two-year ILP licensure period. FirstEnergy expects FERC to issue the new license within the remaining portion of the two-year ILP period. To the extent, however, that the license proceedings extend beyond the February 28, 2013 expiration date for the current license, the current license will be extended yearly as necessary to permit FERC to issue the new license.
Seneca

The Seneca Pumped Storage Project is a451MW hydroelectric project located in Warren County, Pennsylvania owned and operated by FGCO. FGCO holds the current FERC license that authorizes ownership and operation of the project. The current FERC license will expire on November 30, 2015. FERC's regulations call for a five-year relicensing process. On November 24, 2010, and acting pursuant to applicable FERC regulations and rules, FGCO initiated the relicensing process by filing its notice of intent to relicense and PAD in the license docket.

On November 30, 2010, the Seneca Nation filed its notice of intent to relicense and PADs necessary for them to submit a competing application. Section 15 of the FPA contemplates that third parties may file a "competing application" to assume ownership and operation of a hydroelectric facility upon (i) relicensure and (ii) payment of net book value of the plant to the original owner/operator. Nonetheless, FGCO believes it is entitled to a statutory “incumbent preference” under Section 15.

The Seneca Nation and certain other intervenors have asked FERC to redefine the “project boundary” of the hydroelectric plant to include the dam and reservoir facilities operated by the U.S. Army Corps of Engineers. On May 16, 2011, FirstEnergy filed a Petition for Declaratory Order with FERC seeking an order to exclude the dam and reservoir facilities from the project. The Seneca Nation, the New York State Department of Environmental Conservation, and the U.S. Department of Interior each submitted responses to FirstEnergy's petition, including motions to dismiss FirstEnergy's petition. The “project boundary” issue is pending before FERC.

On September 12, 2011, FirstEnergy and the Seneca Nation each filed “Revised Study Plan” documents. These documents describe the parties' respective proposals for the scope of the environmental studies that should be performed as part of the relicensing process. On October 11, 2011, FERC Staff issued a letter order that addressed the Revised Study Plans. In the order, FERC Staff approved FirstEnergy's Revised Study Plan, subject to a finding that the Project is located on “aboriginal lands” of the Seneca Nation. Based on this finding, FERC Staff directed FirstEnergy to consult with the Seneca Nation and other parties about the data set, methodology, and modeling of the hydrological impacts of project operations. FirstEnergy is performing the work necessary to develop a study proposal from which to conduct such consultations. The study process will extend through approximately November of 2013.


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FirstEnergy cannot predict the outcome of this matter or estimate the possible loss or range of loss.
ENVIRONMENTAL MATTERS
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. Compliance with environmental regulations could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that FirstEnergy 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.
CAA Compliance
FirstEnergy is required to meet federally-approved SO2and NOx emissions regulations under the CAA. FirstEnergy complies with SO2and NOx reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, combustion controls and post-combustion controls, generating more electricity from lower or non-emitting plants and/or using emission allowances. Violations can result in the shutdown of the generating unit involved and/or civil or criminal penalties.
In July 2008,threecomplaints were filed against FGCO in the U.S. District Court for the Western District of Pennsylvania seeking damages based on air emissions from the coal-fired Bruce Mansfield Plant.Twoof these 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 oftwenty-oneindividuals and the other being a class action complaint seeking certification as a class action with theeightnamed plaintiffs as the class representatives. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these complaints.
The states of New Jersey and Connecticut filed CAA citizen suits in 2007 alleging NSR violations at the coal-fired Portland Generation Station against GenOn Energy, Inc. (formerly RRI Energy, Inc. and the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999) and Met-Ed. Specifically, these suits allege that “modifications” at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR permitting in violation of the CAA's PSD program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. In September 2009, the Court granted Met-Ed's motion to dismiss New Jersey's and Connecticut's claims for injunctive relief against Met-Ed, but denied Met-Ed's motion to dismiss the claims for civil penalties. The parties dispute the scope of Met-Ed's indemnity obligation to and from Sithe Energy, and Met-Ed is unable to predict the outcome of this matter or estimate the possible loss or range of loss.
In January 2009, the EPA issued a NOV to GenOn Energy, Inc. alleging NSR violations at the coal-fired Portland Generation Station based on “modifications” dating back to 1986. The NOV also alleged NSR violations at the Keystone and Shawville coal-fired plants based on “modifications” dating back to 1984. Met-Ed, JCP&L and Penelec are unable to predict the outcome of this matter or estimate the possible loss or range of loss.
In each of May and September 2010, New Jersey submitted interstate pollution transport petitions seeking to reduce Portland Generating Station air emissions under section 126 of the CAA. Based on the September 2010 petition, the EPA has finalized emissions limits and compliance schedules to reduce SO2air emissions by approximately 81% at the Portland Station by January 6, 2015. New Jersey's May 2010 petition is still under consideration by the EPA.
In June 2008, the EPA issued a Notice and Finding of Violation to Mission alleging that “modifications” at the coal-fired Homer City Plant occurred from 1988 to the present without preconstruction NSR permitting in violation of the CAA's PSD program. In May 2010, the EPA issued a second NOV to Mission, Penelec, NYSEG and others that have had an ownership interest in Homer City containing in all material respects allegations identical to those included in the June 2008 NOV. In January 2011, the DOJ filed a complaint against Penelec in the U.S. District Court for the Western District of Pennsylvania seeking injunctive relief against Penelec based on alleged “modifications” at Homer City between 1991 to 1994 without preconstruction NSR permitting in violation of the CAA's PSD and Title V permitting programs. The complaint was also filed against the former co-owner, NYSEG, and various current owners of Homer City, including EME Homer City Generation L.P. and affiliated companies, including Edison International. In addition, the Commonwealth of Pennsylvania and the States of New Jersey and New York intervened and have filed separate complaints regarding Homer City seeking injunctive relief and civil penalties. In January 2011, another complaint was filed against Penelec and the other entities described above in the U.S. District Court for the Western District of Pennsylvania seeking damages based on Homer City's air emissions as well as certification as a class action and to enjoin Homer City from operating except in a “safe, responsible, prudent and proper manner.” In October 2011, the Court dismissed all of the claims with prejudice of the U.S. and the Commonwealth of Pennsylvania and the States of New Jersey and New York and all of the claims of the private parties, without prejudice to re-file state law claims in state court, against all of the defendants, including Penelec.In December 2011, the U.S., the Commonwealth of Pennsylvania and the States of New Jersey and New York all filed notices appealing to the Third Circuit Court of Appeals. Penelec believes the claims are without merit and intends to defend itself against the allegations made in these complaints, but, at this time, is unable to predict the outcome of this matter or estimate the loss or possible range of loss. Mission is seeking indemnification from NYSEG and Penelec, the co-owners of Homer City prior to its sale in 1999. On February 13, 2012, the Sierra Club notified the current owner and operator of Homer City, Homer City OL1-OL8 LLC and EME Homer City Generation L.P., that it intends to file a CAA citizen suit regarding its Title V permit and SO2 emissions from the Homer City Plant.
In August 2009, the EPA issued a Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, including the


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PSD, NNSR and Title V regulations, at the Eastlake, Lakeshore, Bay Shore and Ashtabula coal-fired plants. The EPA's NOV alleges equipment replacements during maintenance outages dating back to 1990 triggered the pre-construction permitting requirements under the PSD and NNSR programs. FGCO also received a request for certain operating and maintenance information and planning information for these same generating plants and notification that the EPA is evaluating whether certain maintenance at the Eastlake Plant may constitute a major modification under the NSR provisions of the CAA. Later in 2009, FGCO also received another information request regarding emission projections for the Eastlake Plant. In June 2011, EPA issued another Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, specifically opacity limitations and requirements to continuously operate opacity monitoring systems at the Eastlake, Lakeshore, Bay Shore and Ashtabula coal-fired plants. Also, in June 2011, FirstEnergy received an information request pursuant to section 114(a) of the CAA for certain operating, maintenance and planning information, among other information regarding these plants. 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 or estimate the possible loss or range of loss.
In August 2000, AE received an information request pursuant to section 114(a) of the CAA from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the followingtencoal-fired plants, which collectively include22electric generation units: Albright, Armstrong, Fort Martin, Harrison, Hatfield's Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island to determine compliance with the NSR provisions under the CAA, which can require the installation of additional air emission control equipment when a major modification of an existing facility results in an increase in emissions. AE has provided responsive information to this and a subsequent request but is unable to predict the outcome of this matter or estimate the possible loss or range of loss.
In May 2004, AE, AE Supply, MP and WP received a Notice of Intent to Sue Pursuant to CAA §7604 from the Attorneys General of New York, New Jersey and Connecticut and from the PA DEP, alleging that Allegheny performed major modifications in violation of the PSD provisions of the CAA at the following West Virginia coal-fired generation units: Albright Unit 3; Fort Martin Units 1 and 2; Harrison Units 1, 2 and 3; Pleasants Units 1 and 2 and Willow Island Unit 2. The Notice also alleged PSD violations at the Armstrong, Hatfield's Ferry and Mitchell coal-fired plants in Pennsylvania and identifies PA DEP as the lead agency regarding those facilities. In September 2004, AE, AE Supply, MP and WP received a separate Notice of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.
In June 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed suit against AE, AE Supply, MP, PE and WP in the United States District Court for the Western District of Pennsylvania alleging, among other things, that Allegheny performed major modifications in violation of the CAA and the Pennsylvania Air Pollution Control Act at the coal-fired Hatfield's Ferry, Armstrong and Mitchell Plants in Pennsylvania. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. A non-jury trial on liability only was held in September 2010. Plaintiffs filed their proposed findings of fact and conclusions of law in December 2010, Allegheny made its related filings in February 2011 and plaintiffs filed their responses in April 2011. The parties are awaiting a decision from the District Court, but there is no deadline for that decision and we are unable to predict the outcome or estimate the possible loss or range of loss.
In September 2007, Allegheny received a NOV from the EPA alleging NSR and PSD violations under the CAA, as well as Pennsylvania and West Virginia state laws at the coal-fired Hatfield's Ferry and Armstrong plants in Pennsylvania and the coal-fired Fort Martin and Willow Island plants in West Virginia.
FirstEnergy intends to vigorously defend against the CAA matters described above but cannot predict their outcomes or estimate the possible loss or range of loss.
State Air Quality Compliance
In early 2006, Maryland passed the Healthy Air Act, which imposes state-wide emission caps on SO2and NOx, requires mercury emission reductions and mandates that Maryland join the RGGI and participate in that coalition's regional efforts to reduce CO2emissions. On April 20, 2007, Maryland became the tenth state to join the RGGI. The Healthy Air Act provides a conditional exemption for the R. Paul Smith coal-fired plant for NOx, SO2and mercury, based on a 2006 PJM declaration that the plant is vital to reliability in the Baltimore/Washington DC metropolitan area. Pursuant to the legislation, the MDE passed alternate NOx and SO2limits for R. Paul Smith, which became effective in April 2009. However, R. Paul Smith is still required to meet the Healthy Air Act mercury reductions of80%which began in 2010. The statutory exemption does not extend to R. Paul Smith's CO2emissions. Maryland issued final regulations to implement RGGI requirements in February 2008.FourteenRGGI auctions have been held through the end of calendar year 2011. RGGI allowances are also readily available in the allowance markets, affording another mechanism by which to secure necessary allowances. On March 14, 2011, MDE requested PJM perform an analysis to determine if termination of operation at R. Paul Smith would adversely impact the reliability of electrical service in the PJM region under current system conditions. On June 30, 2011, PJM notified MDE that termination of operation at R. Paul Smith would adversely impact the reliability of electrical service in the PJM region absent transmission system upgrades. On January 26, 2012, FirstEnergy announced that R. Paul Smith is among nine coal-fired plants it intends to retire by September 1, 2012, subject to review of reliability impacts by PJM. FirstEnergy is unable to predict the outcome of this matter or estimate the possible loss or range of loss.
In January 2010, the WVDEP issued a NOV for opacity emissions at the Pleasants coal-fired plant. In August 2011, FirstEnergy and WVDEP resolved the NOV through a Consent Order requiring installation of a reagent injection system to reduce opacity by September 2012.


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National Ambient Air Quality Standards
The EPA's CAIR requires reductions of NOx and SO2emissions intwophases (2009/2010 and 2015), ultimately capping SO2emissions in affected states to2.5 milliontons annually and NOx emissions to1.3 milliontons annually. In 2008, the U.S. Court of Appeals for the District of Columbia vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” In December 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 two-step approach,new rule consistent with the Court's opinion. The Court ruled in a more-likely-than-not recognition criteriondifferent case that a cap-and-trade program similar to CAIR, called the “NOx SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the “8-hour” ozone NAAQS. In July 2011, the EPA finalized the CSAPR, to replace CAIR,requiring reductions of NOx and SO2emissions intwo phases (2012 and 2014), ultimately capping SO2emissions in affected states to2.4 milliontons annually and NOx emissions to1.2 milliontons annually. CSAPR allows trading of NOx and SO2emission allowances between power plants located in the same state and interstate trading of NOx and SO2emission allowances with some restrictions. On February 21, 2012, the EPA revised certain CASPR state budgets (for Florida, Louisiana, Michigan, Mississippi, Nebraska, New Jersey, New York, Texas, and Wisconsin and new unit set-asides in Arkansas and Texas), certain generating unit allocations (for some units in Alabama, Indiana, Kansas, Kentucky, Ohio and Tennessee) for NOx and SO2emissions and delayed from 2012 to 2014 certain allowance penalties that could apply with respect to interstate trading of NOx and SO2emission allowances.On December 30, 2011, CSAPR was stayed by the U.S. Court of Appeals for the District of Columbia Circuit pending a measurement attributedecision on legal challenges raised in appeals filed by various stakeholders and scheduled to be argued before the Court on April 13, 2012. The Court ordered EPA to continue administration of CAIR until the Court resolves the CSAPR appeals. Depending on the outcome of these proceedings and how any final rules are ultimately implemented, FGCO's and AE Supply's future cost of compliance may be substantial and changes to FirstEnergy's operations may result.

During 2011, FirstEnergy recorded pre-tax impairment charges of approximately$6 million($1 millionfor FES and$5 millionfor AE Supply) for NOx emission allowances that measures the position as the largest amount of tax benefit that is greater than 50% likely of being ultimately realized upon ultimate settlement. If it is not more likely than not that the benefit will be sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. The Company recognizes interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized and the amount previously taken orwere expected to be obsolete after 2011 and approximately$21 million($18 millionfor FES and$3 millionfor AE Supply) for excess SO2emission allowances in inventory that it expects will not be consumed in the future.
Hazardous Air Pollutant Emissions
On December 21, 2011, the EPA finalized the MATS to establish emission standards for mercury, hydrochloric acid and various metals for electric generating units. The MATS establishes emission limits for mercury, PM, and HCL for all existing and new coal-fired electric generating units effective in April 2015 and allows averaging of emissions from multiple units located at a single plant. Under the CAA, state permitting authorities can grant an additional compliance year through April 2016, as needed, including instances when necessary to maintain reliability where electric generating units are being closed. In addition, an EPA enforcement policy document contemplates up to an additional year to achieve compliance, through April 2017, under certain circumstances for reliability critical units. On January 26, 2012 and February 8, 2012, FGCO, MP and AE Supply announced the retirement by September 1, 2012 (subject to a reliability review by PJM) of nine coal-fired power plants (Albright, Armstrong, Ashtabula, Bay Shore except for generating unit 1, Eastlake, Lake Shore, R. Paul Smith, Rivesville and Willow Island) with a total capacity of3,349megawatts (generating, on average, approximately ten percent of the electricity produced by the companies over the past three years) due to MATS and other environmental regulations. In addition, MP will make a filing with the WVPSC to provide them with information regarding the retirement of its plants. Depending on how the MATS are ultimately implemented, FirstEnergy's future cost of compliance with MATS may be substantial and other changes to FirstEnergy's operations may result.
On February 24, 2012, PJM notified FirstEnergy of its preliminary analysis of the reliability impacts that may result from closure of the older competitive coal-fired generating units. PJM's preliminary analysis indicated that there would be significant reliability concerns that will need to be addressed. FirstEnergy intends to continue to actively engage in discussions with PJM regarding this notification, including the possible continued operation of certain plants.
Climate Change
There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. 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, in June 2009. Certain states, primarily the northeastern states participating in the RGGI and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.
In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that required FirstEnergy to measure and report GHG emissions commencing in 2010. In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA's finding concludes that concentrations of several key GHGs increase the threat of climate change and may be regulated as “air pollutants” under the CAA. In April 2010, the EPA finalized new 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 would not be triggered for electric generating plants and other stationary sources until January 2, 2011, at the earliest. In May 2010, the EPA finalized new thresholds for GHG emissions that define when permits under the CAA's NSR program would be required. The EPA established an emissions applicability threshold of75,000tons per year of CO2equivalents effective January 2, 2011, for existing facilities under the CAA's PSD program.


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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 man-made GHG, including CO2, emitted by developed countries by 2012. A December 2009 U.N. Climate Change Conference in Copenhagen did not reach a consensus on a successor treaty to the Kyoto Protocol, but did take note of the Copenhagen Accord, a non-binding political agreement that recognized the scientific view that the increase in global temperature should be belowtwodegrees Celsius; includes a commitment by developed countries to provide funds, approaching$30 billionover three years with a goal of increasing to$100 billionby 2020; and establishes the “Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. To the extent that 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 targets from 2020, while developing countries, including Brazil, China and India, would agree to take mitigation actions, subject to their domestic measurement, reporting and verification.A December 2011 U.N. Climate Change Conference in Durban, Africa, established a negotiating process to develop a new post-2020 climate change protocol, called the “Durban Platform for Enhanced Action”. This negotiating process contemplates developed countries, as well as developing countries such as China, India, Brazil, and South Africa, to undertake legally binding commitments post-2020. In addition, certain countries agreed to extend the Kyoto Protocol for a second commitment period, commencing in 2013 and expiring in 2018 or 2020.
In 2009, the U.S. Court of Appeals for the Second Circuit and 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. 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. The U.S. Supreme Court granted a writ of certiorari to review the decision of the Second Circuit. On June 20, 2011, the U.S. Supreme Court reversed the Second Circuit but failed to answer the question of the extent to which actions for damages based on GHG emissions may remain viable. The Court remanded to the Second Circuit the issue of whether the CAA preempted state common law nuisance actions.
FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO2emissions per KWH of electricity generated by FirstEnergy is lower than many of its regional competitors due to its diversified generation sources, which include low or non-CO2emitting gas-fired and nuclear generators.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal CWA and its amendments, apply to FirstEnergy's plants. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy's operations.
In 2004, the EPA established new performance standards under Section 316(b) of the CWA for reducing impacts on fish and shellfish from cooling water intake structures at certain existing electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). In 2007, the Court of Appeals for the Second Circuit invalidated portions of the Section 316(b) performance standards and the EPA has taken the position 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. In April 2009, the U.S. Supreme Court reversed one significant aspect of the Second Circuit's opinion and decided that Section 316(b) of the CWA authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. On March 28, 2011, the EPA released a new proposed regulation under Section 316(b) of the CWA generally requiring fish impingement to be reduced to a12%annual average and studies to be conducted at the majority of our existing generating facilities to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic life. On July 19, 2011, the EPA extended the public comment period for the new proposed Section 316(b) regulation by30days but stated its schedule for issuing a final rule remains July 27, 2012. FirstEnergy is studying various control options and their costs and 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. Depending on the tax return.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.
In April 2011, the U.S. Attorney's Office in Cleveland, Ohio advised FGCO that it is no longer considering prosecution under the CWA 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. On August 5, 2011, EPA issued an information request pursuant to Sections 308 and 311 of the CWA for certain information pertaining to the oil spills and spill prevention measures at FirstEnergy includes net interestfacilities. FirstEnergy responded on October 10, 2011. On February 1, 2012, FirstEnergy executed a tolling agreement with the EPA extending the statute of limitations to July 31, 2012. FGCO does not anticipate any losses resulting from this matter to be material.
In May 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and penaltiesthe Sierra Club filed a CWA citizen suit alleging violations of arsenic limits in the provisionNPDES water discharge permit for income taxes.the fly ash impoundments at the Albright Station seeking unspecified civil penalties and injunctive relief. The MP filed an answer on July 11, 2011, and a motion to stay the proceedings


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on July 13, 2011. On January 3, 2012, the Court denied MP's motion to dismiss or stay the CWA citizen suit but without prejudice to re-filing in the future. MP is currently seeking relief from the arsenic limits through WVDEP agency review.
In June 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club served a60-Day Notice of Intent required prior to filing a citizen suit under the CWA for alleged failure to obtain a permit to construct the fly ash impoundments at the Albright Plant.
FirstEnergy intends to vigorously defend against the CWA matters described above but, except as indicated above, cannot predict their outcomes or estimate the possible loss or range of loss.
Monongahela River Water Quality
In late 2008, the PA DEP imposed water quality criteria for certain effluents, including TDS and sulfate concentrations in the Monongahela River, on new and modified sources, including the scrubber project at the coal-fired Hatfield's Ferry Plant. These criteria are reflected in the current PA DEP water discharge permit for that project. AE Supply appealed the PA DEP's permitting decision, which would require it to incur estimated costs in excess of$150 millionin order to install technology to meet TDS and sulfate limits in the permit or negatively affect its ability to operate the scrubbers as designed. The permit has been independently appealed by Environmental Integrity Project and Citizens Coal Council, which seeks to impose more stringent technology-based effluent limitations. Those same parties have intervened in the appeal filed by AE Supply, and both appeals have been consolidated for discovery purposes. An order has been entered that stays the permit limits that AE Supply has challenged while the appeal is pending. A hearing on the parties' appeals was scheduled to begin in September 2011, however the Court stayed all prehearing deadlines on July 15, 2011 to allow the parties additional time to work out a settlement, and has rescheduled a hearing, if necessary, for July 2012. If these settlement discussions are successful, AE Supply anticipates that its obligations will not be material. AE Supply intends to vigorously pursue these issues, but cannot predict the outcome of these appeals or estimate the possible loss or range of loss.
In a business combination,parallel rulemaking, the PA DEP recommended, and in August 2010, the Pennsylvania Environmental Quality Board issued, a final rule imposing end-of-pipe TDS effluent limitations. FirstEnergy could incur significant costs for additional control equipment to meet the requirements of this rule, although its provisions do not apply to electric generating units until the end of 2018, and then only if the EPA has not promulgated TDS effluent limitation guidelines applicable to such units.
In December 2010, PA DEP submitted its CWA 303(d) list to the EPA with a recommended sulfate impairment designation for an approximately68mile stretch of the Monongahela River north of the West Virginia border. In May 2011, the EPA agreed with PA DEP's recommended sulfate impairment designation. PA DEP's goal is to submit a final water quality standards regulation, incorporating the sulfate impairment designation for EPA approval by May, 2013. PA DEP will then need to develop a TMDL limit for the river, a process that will take approximatelyfiveyears. Based on the stringency of the TMDL, FirstEnergy may incur significant costs to reduce sulfate discharges into the Monongahela River from the coal-fired Hatfield's Ferry and Mitchell Plants in Pennsylvania and the coal-fired Fort Martin Plant in West Virginia.
In October 2009, the WVDEP issued the water discharge permit for the Fort Martin Plant. Similar to the Hatfield's Ferry water discharge permit, the Fort Martin permit imposes effluent limitations for TDS and sulfate concentrations. The permit also imposes temperature limitations and other effluent limits for heavy metals that are not contained in the Hatfield's Ferry water discharge permit. Concurrent with the issuance of the Fort Martin permit, WVDEP also issued an administrative order that sets deadlines for MP to meet certain of the effluent limits that are effective immediately under the terms of the permit. MP appealed the Fort Martin permit and the administrative order. The appeal included a request to stay certain of the conditions of the permit and order while the appeal is pending, which was granted pending a final decision on appeal and subject to WVDEP moving to dissolve the stay. The appeals have been consolidated. MP moved to dismiss certain of the permit conditions for the failure of the WVDEP to submit those conditions for public review and comment during the permitting process. An agreed-upon order that suspends further action on this appeal, pending WVDEP's release for public review and comment on those conditions, was entered on August 11, 2010. The stay remains in effect during that process. The current terms of the Fort Martin permit would require MP to incur significant costs or negatively affect operations at Fort Martin. Preliminary information indicates an initial capital investment in excess of the purchase price overcapital investment that may be needed at Hatfield's Ferry in order to install technology to meet the estimated fair valuesTDS and sulfate limits in the Fort Martin permit, which technology may also meet certain of the assets acquiredother effluent limits in the permit. Additional technology may be needed to meet certain other limits in the permit. MP intends to vigorously pursue these issues but cannot predict the outcome of these appeals or estimate the possible loss or range of loss.
Regulation of Waste Disposal
Federal and liabilities assumed is recognizedstate hazardous waste regulations have been promulgated as goodwill. Based ona result of the guidance provided by accounting standards for the recognition, subsequent measurement,Resource Conservation and subsequent recognitionRecovery Act of goodwill, we evaluate goodwill for impairment at least annually and make such evaluations more frequently if indicators of impairment arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If impairment is indicated, we recognize a loss – calculated1976, as the difference between the implied fair value of a reporting unit's goodwillamended, and the carrying valueToxic Substances Control Act of 1976. Certain fossil-fuel combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the goodwill. The forecasts usedneed for future regulation. In February 2009, the EPA requested comments from the states on options for regulating coal combustion residuals, including whether they should be regulated as hazardous or non-hazardous waste.
In December 2009, in our evaluationsan advance notice of goodwill reflect operations consistent with our general business assumptions. Unanticipated changes in those assumptionspublic rulemaking, the EPA asserted that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. In May 2010, the EPA proposedtwooptions for additional


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regulation of coal combustion residuals, including the option of regulation as a special waste under the EPA's hazardous waste management program which could have a significant effectimpact on the management, beneficial use and disposal of coal combustion residuals. FirstEnergy's future cost of compliance with any coal combustion residuals regulations that 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. Compliance with those regulations could have an adverse impact on FirstEnergy's results of operations and financial condition.
LBR CCB impoundment is expected to run out of disposal capacity for disposal of CCBs from the BMP between 2016 and 2018. BMP is pursuing several CCB disposal options.
Certain of our 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 ofDecember 31, 2011, based on estimates of the total costs of cleanup, the Utility Registrants' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay.Total liabilities of approximately$106 million(JCP&L -$70 million, TE -$1 million, CEI -$1 million, FGCO -$1 millionand FE -$33 million) have been accrued throughDecember 31, 2011. Included in the total are accrued liabilities of approximately$63 millionfor 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. On July 11, 2011, FirstEnergy was found to be a potentially responsible party under CERCLA, indirectly liable for a portion of past and future clean-up costs at certain legacy MGP sites, estimated to total approximately$59 million. FirstEnergy recognized an additional expense of$29 millionduring the second quarter of 2011;$30 millionhad previously been reserved prior to 2011.FirstEnergy determined that it is reasonably possible that it or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the possible losses or range of losses cannot be determined or reasonably estimated at this time.
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.Twoclass action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages due to the outages. After various motions, rulings and appeals, the Plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, strict product liability and punitive damages were dismissed, leaving only the negligence and breach of contract causes of actions. On July 29, 2010, the Appellate Division upheld the trial court's decision decertifying the class. In November 2010, the Supreme Court issued an order denying Plaintiffs' motion for leave to appeal. The Court's order effectively ends the attempt to certify the class, and leaves only9plaintiffs to pursue their respective individual claims. The matter was referred back to the lower court, which set a trial date for February 13, 2012, for the remaining individual plaintiffs. Plaintiffs have accepted an immaterial amount in final settlement of all matters and the settlement documentation is being finalized for execution by all parties.
Nuclear Plant Matters
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As ofDecember 31, 2011, FirstEnergy had approximately$2 billioninvested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy's NDT fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy's obligation to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the NDT. On March 28, 2011, FENOC submitted its biennial report on nuclear decommissioning funding to the NRC. This submittal identified a total shortfall in nuclear decommissioning funding for Beaver Valley Unit 1 and Perry of approximately$92.5 million. By letter dated December 29, 2011, FENOC informed the NRC staff that it had increased the parental guarantee to$95 million.
In January 2004, subsidiaries of FirstEnergy filed a lawsuit in the U.S. Court of Federal Claims seeking damages in connection with costs incurred at the Beaver Valley, Davis-Besse and Perry nuclear facilities as a result of the DOE's failure to begin accepting spent nuclear fuel on January 31, 1998. DOE was required to begin accepting spent nuclear fuel by the Nuclear Waste Policy Act (42 USC 10101 et seq) and the contracts entered into by the DOE and the owners and operators of these facilities pursuant to the Act.In January 2012, the applicable FirstEnergy affiliates reached a$48 millionsettlement of these claims.

In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse operating license for an additional twenty years, until 2037. By an order dated April 26, 2011, a NRC ASLB granted a hearing on the Davis-Besse license renewal application to a group of petitioners. By this order, the ASLB also admitted two contentions challenging whether FENOC's Environmental Report adequately evaluated (1) a combination of renewable energy sources as alternatives to the renewal of Davis-Besse's operating license, and (2) severe accident mitigation alternatives at Davis-Besse. On May 6, 2011, FENOC filed an appeal with the NRC from the order granting a hearing on the Davis-Besse license renewal application.On January 10, 2012, intervenors petitioned the ASLB for a new contention on the cracking of the Davis-Besse shield building discussed below.


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On October 1, 2011, Davis-Besse was safely shut down for a scheduled outage to install a new reactor vessel head and complete other maintenance activities. The new reactor head, which replaced a head installed in 2002, enhances safety and reliability, and features control rod nozzles made of material less susceptible to cracking. On October 10, 2011, following opening of the building for installation of the new reactor head, a sub-surface hairline crack was identified in one of the exterior architectural elements on the shield building. These elements serve as architectural features and do not have structural significance. During investigation of the crack at the shield building opening, concrete samples and electronic testing found similar sub-surface hairline cracks in most of the building's architectural elements. FENOC's investigation also identified other indications. Included among them were sub-surface hairline cracks in the upper portion of the shield building (above elevation 780') and in the vicinity of the main steam line penetrations.A team of industry-recognized structural concrete experts and Davis-Besse engineers has determined these conditions do not affect the facility's structural integrity or safety.
On December 2, 2011, the NRC issued a CAL which concluded that FENOC provided "reasonable assurance that the shield building remains capable of performing its safety functions." The CAL imposed a number of commitments from FENOC including, submitting a root cause evaluation and corrective actions to the NRC by February 28, 2012, and further evaluations of goodwill.the shield building. On February 27, 2012, FENOC sent the root cause evaluation to the NRC. Finally, the CAL also stated that the NRC was still evaluating whether the current condition of the shield building conforms to the plant's licensing basis. On December 6, 2011, the Davis-Besse plant returned to service.
By letter dated August 25, 2011, the NRC made a final significance determination (white) associated with a violation that occurred during the retraction of a source range monitor from the Perry reactor vessel. The NRC also placed Perry in the degraded cornerstone column (Column 3) of the NRC's Action Matrix governing the oversight of commercial nuclear reactors. As a result, the NRC staff will conduct several supplemental inspections, culminating in an inspection using Inspection Procedure 95002 to determine if the root cause and contributing causes of risk significant performance issues are understood, the extent of condition has been identified, whether safety culture contributed to the performance issues, and if FENOC's corrective actions are sufficient to address the causes and prevent recurrence.
In light of the impacts of the earthquake and tsunami on the reactors in Fukushima, Japan, the NRC conducted inspections of emergency equipment at U.S. reactors. The NRC also established a Near-Term Task Force to review its processes and regulations in light of the incident, and, on July 12, 2011, the Task Force issued its report of recommendations for regulatory changes. On October 18, 2011, the NRC approved the Staff recommendations, and directed the Staff to implement its near-term recommendations without delay. Ultimately, the adoption of the Staff recommendations on near-term actions is likely to result in additional costs to implement plant modifications and upgrades required by the regulatory process over the next several years, which costs are likely to be material.
On February 16, 2012, the NRC issued a request for information to the licensed operators of 11 nuclear power plants, including Beaver Valley Power Station Units 1 and 2, with respect to the modeling of fuel performance as it relates to "thermal conductivity degradation," which is the potential in older fuel for reduced capacity to transfer heat that could potentially change its performance during various accident scenarios, including loss of coolant accidents. The request for information indicated that this phenomenon has not been accounted for adequately in performance models for the fuel developed by the fuel manufacturer. The NRC is requesting that FENOC provide an analysis to demonstrate that the NRC regulations are being met. Absent that demonstration, the request indicates that the NRC may consider imposing restrictions on reactor operating limits until the issue is satisfactorily resolved.
ICG Litigation
On December 28, 2006, AE Supply and MP filed a complaint in the Court of Common Pleas of Allegheny County, Pennsylvania against ICG, Anker WV, and Anker Coal. Anker WV entered into a long term Coal Sales Agreement with AE Supply and MP for the supply of coal to the Harrison generating facility. Prior to the time of trial, ICG was dismissed as a defendant by the Court, which issue can be the subject of a future appeal. As a result of defendants' past and continued failure to supply the contracted coal, AE Supply and MP have incurred and will continue to incur significant additional costs for purchasing replacement coal. A non-jury trial was held from January 10, 2011 through February 1, 2011. At trial, AE Supply and MP presented evidence that they have incurred in excess of$80 millionin damages for replacement coal purchased through the end of 2010 and will incur additional damages in excess of$150 millionfor future shortfalls. Defendants primarily claim that their performance is excused under a force majeure clause in the coal sales agreement and presented evidence at trial that they will continue to not provide the contracted yearly tonnage amounts. On May 2, 2011, the court entered a verdict in favor of AE Supply and MP for$104 million($90 millionin future damages and$14 millionfor replacement coal / interest). Post-trial filings occurred in May 2011, with Oral Argument on June 28, 2011. On August 25, 2011, the Allegheny County Court denied all Motions for Post-Trial relief and the May 2, 2011 verdict became final. On August 26, 2011, ICG posted bond and filed a Notice of Appeal. Briefing on the Appeal is concluded with oral argument expected in May or June of 2012. AE Supply and MP intend to vigorously pursue this matter through appeal.

NEW ACCOUNTING STANDARDS AND INTERPRETATIONSOther Legal Matters

In 2009,February 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 FASB amended the derecognition guidancereduction 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 Transfers and Servicing Topicdiscount was approved by the PUCO. In March 2010, the named-defendant companies filed a motion to dismiss the case due to the lack of jurisdiction of the FASB Accounting Standards Codificationcourt of common


99


pleas. The court granted the motion to dismiss on September 7, 2010. The plaintiffs appealed the decision to the Court of Appeals of Ohio.On October 21, 2011, the Court of Appeals rendered its decision affirming the dismissal of the Complaint by the Court of Common Pleas on all counts except for one relating to an allegation of fraud. The Companies timely filed a notice of appeal on December 5, 2011 with the Supreme Court of Ohio challenging this one aspect of the Court of Appeals opinion. The Supreme Court of Ohio has not yet acted on the appeal.

There are various lawsuits, claims (including claims for asbestos exposure) and eliminatedproceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 15, Regulatory Matters.

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 conceptamount of such costs. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a QSPE. The amended guidance requires an evaluationmaterial obligation, it discloses such obligations and the possible loss or range of all existing QSPEsloss and if such estimate can be made. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject 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 toliability based on any of the matters referenced above, it could have a material adverse effect uponon FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
FirstEnergy prepares consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. FirstEnergy's accounting policies require significant judgment regarding estimates and assumptions underling the amounts included in the financial statements.

In 2009, Additional information regarding 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 beneficiaryapplication 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 does not expect this standard to have a material effect upon its financial statements.

In 2010, the FASB amended the Fair Value Measurements and Disclosures Topic of the FASB Accounting Standards Codification to require additional disclosures about 1) transfers of Level 1 and Level 2 fair value measurements, including the reason for transfers, 2) purchases, sales, issuances and settlements in the roll forward of activity in Level 3 fair value measurements, 3) additional disaggregation to include fair value measurement disclosures for each class of assets and liabilities and 4) disclosure of inputs and valuation techniques used to measure fair value for both recurring and nonrecurring fair value measurements.  The amendment is effective for fiscal years beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances and settlements in the roll forward of activity in Level 3 fair value measurements, which is effective for fiscal years beginning after December 15, 2010.  FirstEnergy does not expect this standard to have a material effect upon its financial statements.

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FIRSTENERGY SOLUTIONS CORP.

MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS


FES is a wholly owned subsidiary of FirstEnergy. FES provides energy-related products and services, and through its subsidiaries, FGCO and NGC, owns or leases and operates and maintains FirstEnergy's fossil and hydroelectric generation facilities, and owns FirstEnergy's nuclear generation facilities, respectively. FENOC, a wholly owned subsidiary of FirstEnergy, operates and maintains the nuclear generating facilities.
`
FES' revenues have been primarily derived from the sale of electricity (provided from FES' generating facilities and through purchased power arrangements) to affiliated utility companies to meet all or a portion of their PLR and default service requirements. These affiliated power salesaccounting policies are 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 the Combined Notes to the Consolidated Financial StatementsStatements.
Revenue Recognition
FirstEnergy follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a discussionsystematic basis throughout the month. At the end of Ohio power supply procurement issueseach month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for 2009unbilled sales is recognized. The determination of unbilled sales and beyond. On November 3, 2009, FES, Met-Ed, Penelecrevenues requires management to make estimates regarding electricity available for retail load, transmission and Waverly restated their partial requirements power purchase agreement for 2010. Underdistribution line losses, demand by customer class, applicable billing demands, weather-related impacts, number of days unbilled and tariff rates in effect within each customer class.
Regulatory Accounting
FirstEnergy’s regulated distribution and regulated independent transmission segments are subject to regulations that sets the new agreement, Met-Ed, Penelec,prices (rates) the Utilities, ATSI, TrAIL and Waverly assigned 1,300 MWPATH are permitted to charge customers based on costs that the regulatory agencies determine are permitted to recover. At times, regulators permit the future recovery through rates of existing energy purchasescosts that would be currently charged 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 suppliesexpense by an unregulated company. This ratemaking process results in the eventrecording of failureregulatory assets and liabilities based on anticipated future cash inflows and outflows. FirstEnergy regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future.
Pensions and OPEB Accounting
FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of supplyits employees and non-qualified pension plans that cover certain employees. The plans provide defined benefits based on years of the assigned energy purchase contracts. FES also supplied, through May 31, 2009,service and compensation levels.
FirstEnergy provides a portion of Penn's defaultnon-contributory pre-retirement basic life insurance for employees who are eligible to retire. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.
As described in Note 1, Organization, Basis of Presentation and Significant Accounting Policies, FirstEnergy elected to change its method of recognizing actuarial gains and losses for its defined benefit pension plans and OPEB plans effective in 2011. Previously, FirstEnergy recognized the net actuarial gains and losses as a component of AOCI and amortized the gains and losses into income over the remaining service requirementslife of affected employees within the related plans, to the extent such gains and losses were outside a corridor of the greater of 10% of the market-related value of plan assets or 10% of the plans' projected benefit obligation.

FirstEnergy has elected to immediately recognize the change in the fair value of plan assets and net actuarial gains and losses annually in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. The remaining components of pension and OPEB expense, primarily service, interest, assumed return on assets and prior service costs, will be recorded on a quarterly basis.


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FirstEnergy's funding policy is based on actuarial computations using the projected unit credit method. During 2011, FirstEnergy made pre-tax contributions to its qualified pension plans of $372 million. FirstEnergy made an additional $600 million pre-tax contribution to its qualified pension plan on January 5, 2012. The underfunded status of FirstEnergy’s qualified and non-qualified pension and OPEB plans as of December 31, 2011 was $2.6 billion.
As a result of the merger with AE in 2011, FirstEnergy assumed certain pension and OPEB plans. FirstEnergy measured the funded status of the Allegheny pension plans and OPEB plans as of the merger closing date using discount rates of 5.50% and 5.25%, respectively. The fair values of plan assets for Allegheny's pension plans and OPEB plans at market-basedthe date of the merger were $954 million and $75 million, respectively, and the actuarially determined benefit obligations for such plans as of that date were $1,341 million and $272 million, respectively. The expected returns on plan assets used to calculate net periodic costs for periods in 2011 subsequent to the date of the merger are 8.25% for Allegheny's qualified pension plan and 5.00% for Allegheny's OPEB plans.
In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and OPEB obligations. The assumed discount rates for pensions were 5.00%, 5.50% and 6.00% as of December 31, 2011, 2010 and 2009, respectively. The assumed discount rates for OPEB were 4.75%, 5.00% and 5.75% as of December 31, 2011, 2010 and 2009, respectively.
FirstEnergy’s assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by the pension trusts. In 2011, FirstEnergy’s qualified pensions and OPEB plan assets earned $387 million or 6.05% compared to amounts earned of $492 million, or 10.1% in 2010. The qualified pension and OPEB costs in 2011 and 2010 were computed using an assumed 8.25% and 8.50% rate of return, respectively, on plan assets which generated $486 million and $397 million of expected returns on plan assets, respectively. The expected return of pensions and OPEB assets is based on the trusts’ asset allocation targets and the historical performance of risk-based and fixed income securities. The gains or losses generated as a result of Penn's 2008 competitive solicitations. FES' revenues also include competitive retailthe difference between expected and wholesale salesactual returns on plan assets will increase or decrease future net periodic pension and OPEB cost as the difference is recognized annually in the fourth quarter of each fiscal year.
Based on discounts rates of 5.00% for pension, 4.75% for OPEB and an estimated return on assets of 7.75%, FirstEnergy expects its 2012 pre-tax net periodic postemployment benefit credits (including amounts capitalized) to non-affiliated customersbe approximately $117 million (excluding any actuarial mark-to-market adjustments that would be recognized in Ohio, Pennsylvania, New Jersey, Maryland, Michigan and Illinois. These sales may provide a greater2012). The following table reflects the portion of revenuespensions and OPEB costs that were charged to expense in the three years ended December 31, 2011.
Postemployment Benefits Expense (Credits) 2011 2010 2009
  (In millions)
Pensions $555
 $247
 $377
OPEB (112) (126) (57)
Total $443
 $121
 $320
Health care cost trends continue to increase and will affect future OPEB costs. The 2011 composite health care trend rate assumptions were approximately 7.5-8.5%, compared to 8.0-9.0% in 2010, gradually decreasing to 5% in later years. In determining FirstEnergy’s trend rate assumptions, included are the specific provisions of FirstEnergy’s health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in FirstEnergy’s health care plans, and projections of future medical trend rates. The effect on the pension and OPEB costs from changes in key assumptions are as follows:
Increase in Net Periodic Benefit Costs from Adverse Changes in Key Assumptions
Assumption Adverse Change Pensions OPEB Total
      (In millions)  
Discount rate Decrease by 0.25% $236
 $23
 $259
Long-term return on assets Decrease by 0.25% $16
 $1
 $17
Health care trend rate Increase by 1.0% N/A
 $27
 $27
Emission Allowances
FirstEnergy holds emission allowances for SO2 and NOx in order to comply with programs implemented by the EPA designed to regulate emissions of SO2 and NOx produced by power plants. Emission allowances are either granted by the EPA at zero cost or are purchased at fair value as needed to meet emission requirements. Emission allowances are not purchased with the intent of resale. Emission allowances eligible to be used in the current year are recorded in materials and supplies inventory at their weighted average cost. Emission allowances eligible for use in future years depending upon FES' participation in its Ohio and Pennsylvania utility affiliates' power procurement arrangements.

The demand for electricity produced and sold by FES, along with the price of that electricity, is impacted by conditions in competitive power markets, global economic activity, economic activity in the Midwest and Mid-Atlantic regions, and weather conditions in FirstEnergy’s service territories. The 2009 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.are recorded as other investments. FirstEnergy and FES have taken various actions and instituted a number of changes in operating practices to manage the impact of these external influences. These actions include employee severances, wage reductions, employee and retiree benefit changes, reduced levels of overtime and the use of fewer contractors. The continuation of recessionary economic conditions, coupled with unusually mild weather patterns and the resulting impact on electricity prices and demand, could impact FES’ future operating performance and financial condition and may require further changes in FES’ operations.

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

Results of Operations

Net income increased to $577 million in 2009 from $506 million in 2008 primarily due to higher revenues (principally from the sale of a participation interest in OVEC), lowerrecognizes emission allowance costs as fuel expense during the periods that emissions are produced by generating facilities. Emission allowances that are not needed to meet emission requirements may be sold and increased investment income, partially offset by higher purchased power, includingare reported as a $205 million mark-to-market charge relatedreduction to certain purchased power contracts, and other operating expenses. Obsolete or excess emission allowances follow FirstEnergy's inventory practice that requires the emission allowances to be recorded at the lower of weighted average cost or market value. See Note 11, Impairment of Long-Lived Assets for further information on impairments of emission allowances.


Revenues101

Revenues increased by $210 million in 2009 compared to 2008 primarily due to increases in revenues from retail generation sales and FGCO’s gain from the sale of a 9% participation interest in OVEC, partially offset by lower affiliated wholesale generation sales and decreased transmission revenues. The increase in revenues in 2009 from 2008 is summarized below:

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Revenues by Type of Service 2009  2008  
Increase
(Decrease)
 
  (In millions) 
Non-Affiliated Generation Sales:
         
Retail
 $778  $615  $163 
Wholesale
  669   718   (49)
Total Non-Affiliated Generation Sales
  1,447   1,333   114 
Affiliated Wholesale Generation Sales
  2,843   2,968   (125)
Transmission
  73   150   (77)
Sale of OVEC  participation interest
  252   -   252 
Other
  113   67   46 
Total Revenues
 $4,728  $4,518  $210 

The increase in non-affiliated retail revenues of $163 million resulted from 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, higher unit prices and the inclusion of the transmission-related component in retail prices in Ohio beginning in June 2009. The increase in PJM retail revenue resulted from the acquisition of new customers, higher sales volumes and unit prices. The acquisition of new customers is primarily due to new government aggregation contracts with 60 area communities in Ohio that will provide discounted generation prices to approximately 580,000 residential and small commercial customers. Lower non-affiliated wholesale revenues of $49 million resulted from decreased sales volumes in PJM partially offset by increased capacity prices, increased sales volumes in MISO, and favorable settlements on hedged transactions.

The lower affiliated company wholesale generation revenues of $125 million were due to lower sales volumes to the Ohio Companies combined with lower unit prices to the Pennsylvania Companies, partially offset by higher unit prices to the Ohio Companies and increased sales volumes to the Pennsylvania Companies. The lower sales volumes and higher unit prices to the Ohio Companies reflected the results of the 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 2009 compared to 2008. Additionally, while unit prices for each of the Pennsylvania Companies did not change, the mix of sales among the companies caused the overall price to decline.

The following tables summarize the price and volume factors contributing to changes in revenues from non-affiliated and affiliated generation sales in 2009 compared to 2008:

  Increase 
Source of Change in Non-Affiliated Generation Revenues
 
(Decrease)
 
  (In millions) 
Retail:   
Effect of 8.6% increase in sales volumes $53 
Change in prices  110 
   163 
Wholesale:    
Effect of 13.9% decrease in sales volumes  (100)
Change in prices  51 
   (49)
Net Increase in Non-Affiliated Generation Revenues $114 


  Increase 
Source of Change in Affiliated Generation Revenues
 
(Decrease)
 
  (In millions) 
Ohio Companies:    
Effect of 36.3% decrease in sales volumes $(837)
Change in prices  
645
 
   
(192
)
Pennsylvania Companies:    
Effect of 14.7% increase in sales volumes  97 
Change in prices  
(30
)
   
67
 
Net Decrease in Affiliated Generation Revenues 
$
(125
)
107
Transmission revenues decreased $77 million due primarily to reduced loads following the expiration of the government aggregation programs in Ohio at the end of 2008. In 2009 FGCO sold a 9% participation interest in OVEC resulting in a $252 million ($158 million, after tax) gain. Other revenue increased $46 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 increased by $276 million in 2009 compared to 2008. The following tables summarize the factors contributing to the changes in fuel and purchased power costs in 2009 from 2008:

Source of Change in Fuel and Purchased Power
 
Increase
 (Decrease)
 
  (In millions) 
Fossil Fuel:    
Change due to increased unit costs  $121 
Change due to volume consumed  (320)
   (199)
Nuclear Fuel:    
Change due to increased unit costs  23 
Change due to volume consumed  (12)
   11 
Non-affiliated Purchased Power:    
Power contract mark-to-market adjustment  205 
Change due to increased unit costs  93 
Change due to volume purchased  (80)
   218 
Affiliated Purchased Power:    
Change due to increased unit costs  131 
Change due to volume purchased  (10)
   121 
Net Increase in Fuel and Purchased Power Costs 
$
151
 

Fuel costs decreased $188 million in 2009 compared to 2008 primarily resulting from decreased coal consumption, reflecting lower generation, offset by higher unit prices due to increased fuel costs associated with purchases of eastern coal. Nuclear fuel costs increased slightly due to increased unit prices in 2009 compared to 2008.

Purchased power costs from non-affiliates increased primarily as a result of a mark-to-market charge of $205 million related to certain purchased power contracts (see Note 6) and increased capacity costs, partially offset by reduced volume requirements. Purchases from affiliated companies increased as a result of increased unit costs, partially offset by lower volume requirements.

Other operating expenses increased $99 million in 2009 compared to 2008 primarily due to increased transmission expenses reflecting TSC related to the load serving entity obligations in MISO and increased net congestion and transmission loss expenses in MISO and PJM. Also contributing to the increase was higher employee benefit expenses and higher nuclear operating costs associated with an additional refueling outage in 2009 compared to 2008. These increases were partially offset by increased intercompany billings and lower fossil operating costs primarily due to a reduction in contractor, material, and labor costs, combined with more resources dedicated to capital projects.

Depreciation expense increased by $27 million in 2009 compared to 2008 primarily due to NGC’s increased ownership interest in Beaver Valley Unit 2 and Perry.

Other Income (Expense)

Other income of $40 million in 2009 compared to other expense of $119 million in 2008, resulted primarily from a $155 million increase from gains on the sale of nuclear decommissioning trust investments. During 2009, the majority of the nuclear decommissioning trust holdings were converted to more closely align with the liability being funded.

Market Risk Information

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

108
Commodity Price Risk

FESFirstEnergy is exposed to financial and market risks resulting from the fluctuation offluctuating interest rates and commodity prices, primarily due to fluctuations inincluding prices for electricity, energy transmission, natural gas, coal nuclear fuel and emission allowance prices. To manageenergy transmission. FirstEnergy's Risk Management Committee is responsible for promoting the volatility relating to these exposures, FESeffective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. FirstEnergy uses a variety of non-derivative and derivative instruments for risk management purposes 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 FES’ derivative contracts qualify for the normal purchase and normal sale exception and are therefore excluded from the table below. Contracts that are not exempt from such treatment include certain purchased power contracts modified to financially settle as FES determined that projected short positions in 2010 and 2011 were not expected to materialize based on reductions in PLR obligations and decreased demand due to economic conditions ($205 million). The change in the fair value of commodity derivative contracts related to energy production during 2009 is summarized in the following table:

Increase (Decrease) in the Fair Value of Derivative Contracts
 Non-Hedge  Hedge  Total 
  (In millions) 
Change in the fair value of commodity derivative contracts:         
Outstanding net liability as of January 1, 2009
 $(1) $(41) $(42)
Additions/change in value of existing contracts
  (204)  (1)  (205)
Settled contracts
  -   27   27 
Outstanding net liability as of December 31, 2009
 $(205) $(15) $(220)
             
Net liabilities – derivative contacts as of December 31, 2009 $(205) $(15) $(220)
             
Impact of changes in commodity derivative contracts(*)
            
Income Statement effects (Pre-Tax)
 $(205) $-  $(205)
Balance Sheet effects:
            
OCI (Pre-Tax)
 $-  $26  $26 

(*)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 December 31, 2009 as follows:

Balance Sheet Classification
 Non-Hedge  Hedge  Total 
  (In millions) 
Current-         
Other assets
 $-  $3  $3 
Other liabilities
  (108)  (17)  (125)
             
Non-Current-
            
Other deferred charges
  -   11   11 
Other noncurrent liabilities
  (97)  (12)  (109)
Net liabilities
 $(205) $(15) $(220)

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 9, Fair Value Measurements of the Combined Notes to the Consolidated Financial Statements). Sources of information for the valuation of commodity derivative contracts assets and liabilities as of December 31, 2011 are summarized by year in the following table:


80


Source of Information-
Fair Value by Contract Year
 2012 2013 2014 2015 2016 Thereafter Total
  (In millions)
Prices actively quoted(1)
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Other external sources(2)
 (211) (51) (32) (22) —
 —
 (316)
Prices based on models (21) —
 —
 —
 8
 31
 18
Total(3)
 $(232) $(51) $(32) $(22) $8
 $31
 $(298)
(1)
Represents exchange traded New York Mercantile Exchange futures and options.
(2)
Primarily represents contracts based on broker and IntercontinentalExchange quotes.
(3)
Includes $(301) million in non-hedge commodity derivative contracts that are primarily related to NUG contracts. NUG contracts are subject to regulatory accounting and do not materially impact earnings.
FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. Based on derivative contracts held as of December 31, 2011, an adverse 10% change in commodity prices would decrease net income by approximately $13 million during the next 12 months.
Interest Rate Risk
FirstEnergy’s exposure to fluctuations in market interest rates is reduced since a significant portion of debt has fixed interest rates, as noted in the table below. FirstEnergy is subject to the inherent interest rate risks related to refinancing maturing debt by issuing new debt securities. As discussed in Note 6, Leases of the Combined Notes to the Consolidated Financial Statements, FirstEnergy’s investments in capital trusts effectively reduce future lease obligations, also reducing interest rate risk.
Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income $89
 $100
 $110
 $76
 $23
 $2,008
 $2,406
 $2,456
Average interest rate 8.8% 8.9% 9.0% 9.5% 10.3% 5.4% 6.0%  
Liabilities:                
Long-term Debt:                
Fixed rate $751
 $964
 $866
 $1,330
 $891
 $11,628
 $16,430
 $18,585
Average interest rate 7.3% 5.9% 5.4% 4.7% 5.9% 6.2% 6.1%  
Variable rate 
 $150
 
 
 
 $585
 $735
 $735
Average interest rate   1.8%       0.1% 0.4%  
Equity Price Risk
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 provides a portion of non-contributory pre-retirement basic life insurance for employees who are eligible to retire. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.
The benefit plan assets and obligations are remeasured annually using a December 31 measurement date or as significant triggering events occur. As of December 31, 2011, the FirstEnergy pension plan was invested in approximately 19% of equity securities, 48% of fixed income securities, 21% of absolute return strategies, 6% of real estate, 2% of private equity and 4% of cash. A decline in the value of pension plan assets could result in additional funding requirements. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. During 2011, FirstEnergy made pre-tax contributions to its qualified pension plans of $372 million. FirstEnergy made an additional $600 million pre-tax contribution to the qualified pension plan on January 5, 2012.
NDT funds have been established to satisfy NGC’s and certain of the Utilities’ nuclear decommissioning obligations. As of December 31, 2011, approximately 79% of the funds were invested in fixed income securities, 12% of the funds were invested in equity


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securities and 9% were invested in short-term investments, with limitations related to concentration and investment grade ratings. The investments are carried at their market values of approximately $1,699 million, $258 million and $207 million for fixed income securities, equity securities and short-term investments, respectively, as of December 31, 2011, excluding ($52) million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $26 million reduction in fair value as of December 31, 2011. The decommissioning trusts of JCP&L, Met-Ed and Penelec 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 recognized in earnings the unrealized losses on available-for-sale securities held in their NDT as OTTI. A decline in the value of FirstEnergy’s NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During 2011, approximately $1 million, $4 million and $1 million was contributed to the NDTs of JCP&L, OE and TE, respectively. FENOC has submitted a $95 million parental guarantee to the NRC for a short-fall in nuclear decommissioning funding to Beaver Valley Unit 1 and Perry.
CREDIT RISK
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. FirstEnergy evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. FirstEnergy may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. FirstEnergy monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.
Wholesale Credit Risk
FirstEnergy measures wholesale credit risk as the replacement cost for derivatives in power, natural gas, coal and emission allowances, adjusted for amounts owed to or due from counterparties for settled transactions. The replacement cost of open positions represents unrealized gains, net of any unrealized losses, where FirstEnergy has a legally enforceable right of set-off. FirstEnergy monitors and manages the credit risk of wholesale marketing, risk management and energy transacting operations through credit policies and procedures, which include an established credit approval process, daily monitoring of counterparty credit limits, the use of credit mitigation measures such as margin, collateral and the use of master netting agreements. FirstEnergy aggressively manages the quality of its portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB (S&P).
Retail Credit Risk
FirstEnergy is exposed to retail credit risk through competitive electricity activities, which serve residential, commercial and industrial companies. Retail credit risk results when customers default on contractual obligations or fail to pay for service rendered. This risk represents the loss that may be incurred due to the nonpayment of customer accounts receivable balances, as well as the loss from the resale of energy previously committed to serve customers.
Retail credit risk is managed through established credit approval policies, monitoring customer exposures and the use of credit mitigation measures such as deposits in the form of LOCs, cash or prepayment arrangements.
Retail credit quality is dependent on the economy and the ability of customers to manage through unfavorable economic cycles and other market changes. If the business environment were to be negatively affected by changes in economic or other market conditions, FirstEnergy's retail credit risk may be adversely impacted.
REGULATORY MATTERS
Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent amounts that are expected to be credited to customers through future regulated rates or amounts collected from customers for costs not yet incurred. FirstEnergy and the Utilities net their regulatory assets and liabilities based on federal and state jurisdictions.


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Net regulatory assets on FirstEnergy's and the Utility Registrants' Consolidated Balance Sheets are comprised of the following:
Regulatory Assets FirstEnergy OE CEI TE JCP&L Met-Ed Penelec
  (In millions)
December 31, 2011              
Regulatory transition costs $608
 $—
 $—
 $—
 $424
 $105
 $79
Customer receivables for future income taxes 508
 42
 1
 2
 29
 129
 145
Nuclear decommissioning, decontamination and spent fuel disposal costs (210) —
 —
 —
 (44) (99) (67)
Asset removal costs (240) (34) (60) (23) (147) —
 —
PJM transmission costs 340
 (3) (3) (1) —
 181
 63
Deferred generation costs 382
 125
 224
 37
 —
 (23) (11)
Distribution costs 267
 146
 73
 48
 —
 —
 —
Other 375
 87
 60
 7
 146
 36
 —
Total $2,030
 $363
 $295
 $70
 $408
 $329
 $209
December 31, 2010              
Regulatory transition costs $770
 $—
 $—
 $—
 $591
 $131
 $43
Customer receivables for future income taxes 328
 52
 2
 1
 30
 113
 130
Nuclear decommissioning, decontamination and spent fuel disposal costs (184) —
 —
 —
 (31) (92) (61)
Asset removal costs (237) (24) (47) (19) (147) —
 —
PJM transmission costs 183
 —
 —
 —
 —
 131
 52
Deferred generation costs 386
 125
 226
 35
 —
 —
 —
Distribution costs 426
 216
 155
 55
 —
 —
 —
Other 158
 34
 34
 1
 71
 13
 (1)
Total $1,830
 $403
 $370
 $73
 $514
 $296
 $163

Additionally, FirstEnergy had $381 million of net regulatory liabilities as of December 31, 2011, including $366 million of net regulatory liabilities attributable to Allegheny that are primarily related to asset removal costs. Net regulatory liabilities are classified within Other Noncurrent Liabilities on the Consolidated Balance Sheets.
Regulatory assets that do not earn a current return as of December 31, 2011 totaled approximately $413 million. Regulatory assets that do not earn a return are primarily comprised of certain regulatory transition and PJM transmission costs for Met-Ed and Penelec of $182 million and $115 million, respectively, that are expected to be recovered by 2020, and certain storm damage costs and pension and OPEB costs incurred by JCP&L of $122 million that are expected to be recovered by 2026.

RELIABILITY MATTERS

Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES, AE Supply, FGCO, FENOC, ATSI and TrAIL. The NERC is the ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including RFC. All of FirstEnergy's facilities are located within the RFC region. FirstEnergy actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by the RFC.

FirstEnergy believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such items are found, FirstEnergy develops information about the item and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an item to RFC. Moreover, it is clear that the NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with future new or amended standards cannot be determined at this time; however, 2005 amendments to the FPA provide that all prudent costs incurred to comply with the future reliability standards be recovered in rates. 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 that could have a material adverse effect on its financial condition, results of operations and cash flows.

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 resulting in customers losing power for up to eleven


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hours. 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. NERC has submitted first and second Requests for Information regarding this and another related matter. JCP&L is complying with these requests. JCP&L is not able to predict what actions, if any, the NERC may take with respect to this matter.

On August 23, 2010, FirstEnergy self-reported to RFC a vegetation encroachment event on a Met-Ed230kV line. This event did not result in a fault, outage, operation of protective equipment, or any other meaningful electric effect on any FirstEnergy transmission facilities or systems. On August 25, 2010, RFC issued a notice of enforcement to investigate the incident. FirstEnergy submitted a data response to RFC on September 27, 2010. On July 8, 2011, RFC and Met-Ed signed a settlement agreement to resolve all outstanding issues related to the vegetation encroachment event. The settlement calls for Met-Ed to pay a penalty of$650,000, and for FirstEnergy to perform certain mitigating actions. These mitigating actions include inspecting FirstEnergy's transmission system using LiDAR technology, and reporting the results of inspections, and any follow-up work, to RFC. FirstEnergy was performing the LiDAR work in response to certain other industry directives issued by NERC in 2010. NERC subsequently approved the settlement agreement and, on September 30, 2011, submitted the approved settlement to FERC for final approval. FERC approved the settlement agreement on October 28, 2011. Met-Ed subsequently paid the$650,000penalty and, on December 31, 2011, RFC sent written notice that this matter has been closed.

In 2011, RFC performed routine compliance audits of parts of FirstEnergy's bulk-power system and generally found the audited systems and process to be in full compliance with all audited reliability standards. RFC will perform additional audits in 2012.

MARYLAND
By statute enacted in 2007, the obligation of Maryland utilities to provide SOS to residential and small commercial customers, in exchange for recovery of their costs plus a reasonable profit, was extended indefinitely. The legislation also established a5-year cycle (to begin in 2008) for the MDPSC to report to the legislature on the status of SOS. PE now conducts rolling auctions to procure the power supply necessary to serve its customer load pursuant to a plan approved by the MDPSC. However, the terms on which PE will provide SOS to residential customers after the current settlement expires at the end of 2012 will depend on developments with respect to SOS in Maryland over the coming year, including but not limited to, possible MDPSC decisions in the proceedings discussed below.

The MDPSC opened a new docket in August 2007 to consider matters relating to possible “managed portfolio” approaches to SOS and other matters. “Phase II” of the case addressed utility purchases or construction of generation, bidding for procurement of demand response resources and possible alternatives if the TrAIL and PATH projects were delayed or defeated. It is unclear when the MDPSC will issue its findings in this proceeding.
In September 2009, the MDPSC opened a new proceeding to receive and consider proposals for construction of new generation resources in Maryland. In December 2009, Governor Martin O'Malley filed a letter in this proceeding in which he characterized the electricity market in Maryland as a “failure” and urged the MDPSC to use its existing authority to order the construction of new generation in Maryland, vary the means used by utilities to procure generation and include more renewables in the generation mix. In December 2010, the MDPSC issued an order soliciting comments on a model RFP for solicitation of long-term energy commitments by Maryland electric utilities. PE and numerous other parties filed comments, and on September 29, 2011, the MDPSC issued an order requiring the utilities to issue the RFP crafted by the MDPSC by October 7, 2011. The RFPs were issued by the utilities as ordered by the MDPSC. The order, as amended, indicated that bids were due by January 20, 2012, and that the MDPSC would be the entity evaluating all bids. The Chairman of the MDPSC has stated publicly that several bids were received, but no other information was released. After receipt of further comments from interested parties, including PE, on January 13, 2012, a hearing on whether more generation is needed, irrespective of what bids may have been received, was held on January 31, 2012. There has been no further action on this matter.

In September 2007, the MDPSC issued an order that required the Maryland utilities to file detailed plans for how they will meet the “EmPOWER Maryland” proposal that electric consumption be reduced by10%and electricity demand be reduced by15%, in each case by 2015.

The Maryland legislature in 2008 adopted a statute codifying the EmPOWER Maryland goals. In 2008, PE filed its comprehensive plans for attempting to achieve those goals, asking the MDPSC to approve programs for residential, commercial, industrial, and governmental customers, as well as a customer education program. The MDPSC ultimately approved the programs in August 2009 after certain modifications had been made as required by the MDPSC, and approved cost recovery for the programs in October 2009. Expenditures were estimated to be approximately$101 millionfor the PE programs for the period of 2009 to 2015 and would be recovered over thatsixyear period. Meanwhile, after extensive meetings with the MDPSC Staff and other stakeholders, PE's plans for additional and improved programs for the period 2012-2014 were filed on August 31, 2011. The MDPSC held hearings on PE's and the other utilities' plans in October 2011, and on December 22, 2011, issued an order approving Potomac Edison's plan with various modifications and follow-up assignments. On January 23, 2012, PE filed a Request for Rehearing because additional facts not considered by the MDPSC demonstrate, among other things, that conservation voltage reduction program expenditures should be accorded cost recovery through the EmPOWER surcharge, as has been provided for all other EmPOWER programs as opposed to recovery of those expenditures being addressed in a future base rate case as the MDPSC found in its order.


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In March 2009, the MDPSC issued an order temporarily suspending the right of all electric and gas utilities in the state to terminate service to residential customers for non-payment of bills. The MDPSC subsequently issued an order making various rule changes relating to terminations, payment plans, and customer deposits that make it more difficult for Maryland utilities to collect deposits or to terminate service for non-payment. The MDPSC is continuing to collect data on payment plan and related issues and has adopted regulations that expand the summer and winter “severe weather” termination moratoria when temperatures are very high or very low, fromoneday, as provided by statute, tothreedays on each occurrence.
The Maryland legislature passed a bill on April 11, 2011, which requires the MDPSC to promulgate rules by July 1, 2012 that address service interruptions, downed wire response, customer communication, vegetation management, equipment inspection, and annual reporting. In crafting the regulations, the legislation directs the MDPSC to consider cost-effectiveness, and provides that the MDPSC may adopt different standards for different utilities based on such factors as system design and existing infrastructure, geography, and customer density. Beginning in July 2013, the MDPSC is required to assess each utility's compliance with the new rules, and may assess penalties of up to$25,000per day per violation. The MDPSC convened a working group of utilities, regulators, and other interested stakeholders to address the topics of the proposed rules. A draft of the rules was filed, along with the report of the working group, on October 27, 2011. Hearings to consider the rules and comments occurred over four days between December 8 and 15, 2011, after which revised rules were sent for legislative review. The proposed rules were published in the Maryland Register on February 24, 2012, and a deadline of March 26, 2012, was set for the filing of further comments. A further hearing is required before the rules could become final. Separately, on July 7, 2011, the MDPSC adopted draft rules requiring monitoring and inspections for contact voltage. The draft rules were published in September, 2011. After a further hearing in October, 2011, the final rules were re-published and became effective on November 28, 2011.

NEW JERSEY

On September 8, 2011, the Division of Rate Counsel filed a Petition with the NJBPU asserting that it has reason to believe that JCP&L is earning an unreasonable return on its New Jersey jurisdictional rate base. The Division of Rate Counsel requests that the NJBPU order JCP&L to file a base rate case petition so that the NJBPU may determine whether JCP&L's current rates for electric service are just and reasonable. JCP&L filed an answer to the Petition on September 28, 2011, stating, inter alia, that the Division of Rate Counsel analysis upon which it premises its Petition contains errors and inaccuracies, that JCP&L's achieved return on equity is currently within a reasonable range, and that there is no reason for the NJBPU to require JCP&L to file a base rate case at this time.On November 30, 2011, the NJBPU ordered that the matter be assigned to the NJBPU President to act as presiding officer to set and modify the schedule for this matter as appropriate, decide upon motions, and otherwise control the conduct of this case, without the need for full Board approval. The matter is pending and a schedule for further proceedings has not yet been established.

On September 22, 2011, the NJBPU ordered that JCP&L hire a Special Reliability Master, subject to NJBPU approval, to evaluate JCP&L's design, operating, maintenance and performance standards as they pertain to the Morristown, New Jersey underground electric distribution system, and make recommendations to JCP&L and the NJBPU on the appropriate courses of action necessary to ensure adequate reliability and safety in the Morristown underground network.On October 12, 2011, the Special Reliability Master was selected and on January 31, 2012, the project report was submitted to the Company and NJBPU Staff. On February 10, 2012, the NJBPU accepted the report and directed the Staff to present recommendations on March 12, 2012, on actions required by JCP&L to ensure the safe, reliable operation of the Morristown network.

Pursuant to a formal Notice issued by the NJBPU on September 14, 2011, public hearings were held on September 26 and 27, 2011, to solicit public comments regarding the state of preparedness and responsiveness of the local electric distribution companies prior to, during and after Hurricane Irene. By subsequent Notice issued September 28, 2011, additional hearings were held in October 2011. Additionally, the NJBPU accepted written comments through October 31, 2011 related to this inquiry.On December 4, 2011, the NJBPU Division of Reliability and Security issued a Request for Qualifications soliciting bid proposals from qualified consulting firms to provide expertise in the review and evaluation of New Jersey's electric distribution companies' preparation and restoration to Hurricane Irene and the October 2011 snowstorm. Responsive bids were submitted on January 20, 2012, and the report of selected bidder is to be submitted to the NJPBU 120 days from the date the contract is awarded. On December 14, 2011, the NJBPU Staff filed a report of its preliminary findings and recommendations with respect to the electric utility companies' planning and response to Hurricane Irene and the October 2011 snowstorm. The NJBPU has not indicated what additional action, if any, may be taken as a result of information obtained through this process.

OHIO

The Ohio Companies operate under an ESP, which expires on May 31, 2014. The material terms of the ESP include: generation supplied through a CBP commencing June 1, 2011; a load cap of no less than80%, which also applies to tranches assigned post-auction; a6%generation discount to certain low income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (FES is one of the wholesale suppliers to the Ohio Companies); no increase in base distribution rates through May 31, 2014; and a new distribution rider, Rider DCR, to recover a return of, and on, capital investments in the delivery system. The Ohio Companies also agreed not to recover from retail customers certain costs related to transmission cost allocations by PJM as a result of ATSI's integration into PJM for the longer of the five-year period from June 1, 2011 through May 31, 2015 or when the amount of costs avoided by customers for certain types of products totals$360 milliondependent on the outcome of certain PJM proceedings, agreed to establish a$12 millionfund to assist low income customers over the term of the ESP and agreed to


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additional matters related to energy efficiency and alternative energy requirements.

Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total annual energy savings equivalent to approximately166,000MWH in 2009,290,000MWH in 2010,410,000MWH in 2011,470,000MWH in 2012 and530,000MWH in 2013, with additional savings required through 2025. Utilities were also required to reduce peak demand in 2009 by1%, with an additional0.75%reduction each year thereafter through 2018.

In December 2009, the Ohio Companies filed the requiredthreeyear 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. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers in 2012. The PUCO issued an Opinion and Order generally approving the Ohio Companies'three-year plan, and the Ohio Companies are in the process of implementing those programs included in the Plan. OE fell short of its statutory 2010 energy efficiency and peak demand reduction benchmarks and therefore, on January 11, 2011, it requested that its 2010 energy efficiency and peak demand reduction benchmarks be amended to actual levels achieved in 2010. Moreover, because the PUCO indicated, when approving the 2009 benchmark request, that it would modify the Ohio Companies' 2010 (and 2011 and 2012) energy efficiency benchmarks when addressing the portfolio plan, the Ohio Companies were not certain of their 2010 energy efficiency obligations. Therefore, CEI and TE (each of which achieved its 2010 energy efficiency and peak demand reduction statutory benchmarks) also requested an amendment if and only to the degree one was deemed necessary to bring them into compliance with their yet-to-be-defined modified benchmarks. On May 19, 2011, the PUCO granted the request to reduce the 2010 energy efficiency and peak demand reductions to the level achieved in 2010 for OE, while finding that the motion was moot for CEI and TE. On June 2, 2011, the Ohio Companies filed an application for rehearing to clarify the decision related to CEI and TE. On July 27, 2011, the PUCO denied that application for rehearing, but clarified that CEI and TE could apply for an amendment in the future for the 2010 benchmarks should it be necessary to do so. Failure to comply with the benchmarks or to obtain such an amendment may subject the Ohio Companies to an assessment of a penalty by the PUCO. In addition to approving the programs included in the plan, with only minor modifications, the PUCO authorized the Ohio Companies to recover all costs related to the original CFL program that the Ohio Companies had previously suspended at the request of the PUCO. Applications for Rehearing were filed by the Ohio Companies, Ohio Energy Group and Nucor Steel Marion, Inc. on April 22, 2011, regarding portions of the PUCO's decision, including the method for calculating savings and certain changes made by the PUCO to specific programs. On September 7, 2011, the PUCO denied those applications for rehearing. The PUCO also included a new standard for compliance with the statutory energy efficiency benchmarks by requiring electric distribution companies to offer “all available cost effective energy efficiency opportunities” regardless of their level of compliance with the benchmarks as set forth in the statute.On October 7, 2011, the Ohio Companies, the Industrial Energy Users - Ohio, and the Ohio Energy Group filed applications for rehearing, arguing that the PUCO'S new standard is unlawful. The Ohio Companies also asked the PUCO to withdraw its amendment of CEI's and TE's 2010 energy efficiency benchmarks. The PUCO did not rule on the Applications for Rehearing within thirty days, thus denying them by operation of law. On December 30, 2011, the Ohio Companies filed a notice of appeal with the Supreme Court of Ohio, challenging the PUCO's new standard. No procedural schedule has been established.

Additionally, under SB221, electric utilities and electric service companies are required to serve part of their load in 2011 from renewable energy resources equivalent to1.00%of the average of the KWH they served in 2008-2010; in 2012 from renewable energy resources equivalent to1.50%of the average of the KWH they served in 2009-2011; and in 2013 from renewable energy resources equivalent to2.00%of the average of the KWH they served in 2010-2012. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RECs acquired through thesetwoRFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. In March 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market and reduced the Ohio Companies' aggregate 2009 benchmark to the level of SRECs the Ohio Companies acquired through their 2009 RFP processes, provided the Ohio Companies' 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC benchmark. On April 15, 2011, the Ohio Companies filed an application seeking an amendment to each of their 2010 alternative energy requirements for solar RECs generated in Ohio on the basis that an insufficient quantity of solar resources are available in the market but reflecting solar RECs that they have obtained and providing additional information regarding efforts to secure solar RECs. On August 3, 2011, the PUCO granted the Ohio Companies' force majeure request for 2010 and increased their 2011 benchmark by the amount of SRECs generated in Ohio that the Ohio Companies were short in 2010. On September 2, 2011, the Environmental Law and Policy Center and Nucor Steel Marion, Inc. filed applications for rehearing. The Ohio Companies filed their response on September 12, 2011. These applications for rehearing were denied by the PUCO on September 20, 2011, but as part of its Entry on Rehearing the PUCO opened a new docket to review the Ohio Companies' alternative energy recovery rider. Separately,oneparty has filed a request that the PUCO audit the cost of the Ohio Companies' compliance with the alternative energy requirements and the Ohio Companies' compliance with Ohio law. The PUCO selected auditors to perform a financial and a management audit, and final audit reports are to be filed with the PUCO by May 15, 2012. In August 2011, the Ohio Companies conducted two RFP processes to obtain RECs to meet the statutory benchmarks for 2011 and beyond.

PENNSYLVANIA
The PPUC entered an Order on March 3, 2010 that denied the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, directed Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructed Met-Ed and Penelec to work with the various intervening parties to file a recommendation to the PPUC regarding the establishment of a separate account for all marginal transmission losses


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collected from customers plus interest to be used to mitigate future generation rate increases beginning January 1, 2011. In March 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 to end collection of costs for marginal transmission losses. The PPUC granted the requested stay until December 31, 2010. Pursuant to the PPUC's order, Met-Ed and Penelec filed plans to establish separate accounts for marginal transmission loss revenues and related interest and carrying charges. Pursuant to the plan approved by the PPUC, Met-Ed and Penelec began to refund those amounts to customers in January 2011, and the refunds are continuing over a 29 month period until the full amounts previously recovered for marginal transmission loses are refunded. In April 2010, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania appealing the PPUC's March 3, 2010 Order. On June 14, 2011, the Commonwealth Court issued an opinion and order affirming the PPUC's Order to the extent that it holds that line loss costs are not transmission costs and, therefore, the approximately$254 millionin marginal transmission losses and associated carrying charges for the period prior to January 1, 2011, are not recoverable under Met-Ed's and Penelec's TSC riders. Met-Ed and Penelec filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court and also a complaint seeking relief in the U.S. District Court for the Eastern District of Pennsylvania, which was subsequently amended. The PPUC filed a Motion to Dismiss Met-Ed's and Penelec's Amended Complaint on September 15, 2011. Met-Ed and Penelec filed a Responsive brief in Opposition to the PPUC's Motion to Dismiss on October 11, 2011. Although the ultimate outcome of this matter cannot be determined at this time, Met-Ed and Penelec believe that they should ultimately prevail through the judicial process and therefore expect to fully recover the approximately$254 million($189 millionfor Met-Ed and$65 millionfor Penelec) in marginal transmission losses for the period prior to January 1, 2011.

In each of May 2008, 2009 and 2010, the PPUC approved Met-Ed's and Penelec's annual updates to their TSC rider for the annual periods between June 1, 2008 to 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 PPUC's approval in May 2010 authorized an increase to the TSC for Met-Ed's customers to provide for full recovery by December 31, 2010.

In February 2010, Penn filed a Petition for Approval of its DSP for the period June 1, 2011 through May 31, 2013. In July 2010, the parties to the proceeding filed a Joint Petition for Settlement of all issues. Although the PPUC's Order approving the Joint Petition held that the provisions relating to the recovery of MISO exit fees and one-time PJM integration costs (resulting from Penn's June 1, 2011 exit from MISO and integration into PJM) were approved, it made such provisions subject to the approval of cost recovery by FERC. Therefore, Penn may not put these provisions into effect until FERC has approved the recovery and allocation of MISO exit fees and PJM integration costs.

Pennsylvania adopted Act 129 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, (EE&C Plan), by July 1, 2009, setting forth the utilities' plans to reduce energy consumption by a minimum of1%and3%by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of4.5%by May 31, 2013. Act 129 provides for potentially significant financial penalties to be assessed upon utilities that fail to achieve the required reductions in consumption and peak demand. Act 129 also required utilities to file a SMIP with the PPUC.

The PPUC entered an Order in February 2010 giving final approval to all aspects of the EE&C Plans of Met-Ed, Penelec and Penn and the tariff rider became effective March 1, 2010. On February 18, 2011, the companies filed a petition to approve their First Amended EE&C Plans. On June 28, 2011, a hearing on the petition was held before an ALJ.On December 15, 2011, the ALJ recommended that the amended plans be approved as proposed, and on January 12, 2012, the Commission approved the plans.
WP filed its original EE&C Plan in June 2009, which the PPUC approved, in large part, by Opinion and Order entered in October 2009. In September 2010, WP filed an amended EE&C Plan that is less reliant on smart meter deployment, which the PPUC approved in January 2011.
On August 9, 2011, WP filed a petition to approve its Second Amended EE&C Plan. The proposed Second Revised Plan includes measures and a new program and implementation strategies consistent with the successful EE&C programs of Met-Ed, Penelec and Penn that are designed to enable WP to achieve the post-2011 Act 129 EE&C requirements.On January 6, 2012, a Joint Petition for Settlement of all issues was filed by the parties to the proceeding.

The Pennsylvania Companies submitted a preliminary report on July 15, 2011, and a final report on November 15, 2011, in which they reported on their compliance with statutory May 31, 2011, energy efficiency benchmarks.Met-Ed, Penelec and Penn achieved the 2011 benchmarks; however WP has been unable to provide final results because several customers are still accumulating necessary documentation for projects that may qualify for inclusion in the final results. Preliminary numbers indicate that WP did not achieve its 2011 benchmark and it is not known at this time whether WP will be subject to a fine for failure to achieve the benchmark. WP is unable to predict the outcome of this matter or estimate any possible loss or range of loss.

In December 2009, WP filed a motion to reopen the evidentiary record to submit an alternative smart meter plan proposing, among other things, a less-rapid deployment of smart meters.

In light of the significant expenditures that would be associated with its smart meter deployment plans and related infrastructure upgrades, as well as its evaluation of recent PPUC decisions approving less-rapid deployment proposals by other utilities, WP re-


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evaluated its Act 129 compliance strategy, including both its plans with respect to smart meter deployment and certain smart meter dependent aspects of the EE&C Plan. In October 2010, WP and Pennsylvania's OCA filed a Joint Petition for Settlement addressing WP's smart meter implementation plan with the PPUC. Under the terms of the proposed settlement, WP proposed to decelerate its previously contemplated smart meter deployment schedule and to target the installation of approximately25,000smart meters in support of its EE&C Plan, based on customer requests, by mid-2012. The proposed settlement also contemplates that WP take advantage of the30-month grace period authorized by the PPUC to continue WP's efforts to re-evaluate full-scale smart meter deployment plans. WP currently anticipates filing its plan for full-scale deployment of smart meters in June 2012. Under the terms of the proposed settlement, WP would be permitted to recover certain previously incurred and anticipated smart-meter related expenditures through a levelized customer surcharge, with certain expenditures amortized over a ten-year period. Additionally, WP would be permitted to seek recovery of certain other costs as part of its revised SMIP that it currently intends to file in June 2012, or in a future base distribution rate case.
Following additional proceedings, on March 9, 2011, WP submitted an Amended Joint Petition for Settlement which restates the Joint Petition for Settlement filed in October 2010, adds the PPUC's Office of Trial Staff as a signatory party, and confirms the support or non-opposition of all parties to the settlement.Oneparty retained the ability to challenge the recovery of amounts spent on WP's original smart meter implementation plan. A Joint Stipulation with the OSBA was also filed on March 9, 2011. The PPUC approved the Amended Joint Petition for Full Settlement by order entered June 30, 2011.

By Tentative Order entered in September 2009, the PPUC provided for an additional30-day comment period on whether the 1998 Restructuring Settlement, which addressed how Met-Ed and Penelec were going to implement direct access to a competitive market for the generation of electricity, allows Met-Ed and Penelec to apply over-collection of NUG costs for select and isolated months to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists. In response to the Tentative Order, various parties filed comments objecting to the accounting method utilized by Met-Ed and Penelec.On January 30, 2012, the Commission entered a final order approving Met-Ed's and Penelec's accounting methodology whereby NUG over-collection revenue may be used to reduce non-NUG stranded costs, even if a cumulative NUG stranded cost balance exists.

In the PPUC Order approving the FirstEnergy and Allegheny merger, the PPUC announced that a separate statewide investigation into Pennsylvania's retail electricity market will be conducted with the goal of making recommendations for improvements to ensure that a properly functioning and workable competitive retail electricity market exists in the state. On April 29, 2011, the PPUC entered an Order initiating the investigation and requesting comments from interested parties on eleven directed questions concerning retail markets in Pennsylvania. Met-Ed, Penelec, Penn Power and WP submitted joint comments on June 3, 2011. FES also submitted comments on June 3, 2011. On June 8, 2011, the PPUC conducted an en banc hearing on these issues at which both the Pennsylvania Companies and FES participated and offered testimony.A technical conference was held on August 10, 2011, and a second en banc was held on November 10, 2011, to discuss intermediate steps that can be taken to promote the development of a competitive market. Teleconferences are scheduled through March 2012, with another en banc hearing to be held on March 21, 2012, to explore the future of default service in Pennsylvania following the expiration of the upcoming default service plans on May 31, 2015. Following the issuance of a Tentative Order and comments filed by numerous parties, the Commission entered a final order on December 16, 2011, providing recommendations for components to be included in upcoming default service plans. An intermediate work plan was also presented on December 16, 2011, by Tentative Order, on which initial comments were submitted by Met-Ed, Penelec, Penn and WP on January 17, 2012. FES also submitted comments. Reply comments were submitted on February 1, 2012. It is expected that a final order implementing the intermediate work plan and a long range plan will be presented by the PPUC, both in March 2012.

The PPUC issued a Proposed Rulemaking Order on August 25, 2011, which proposed a number of substantial modifications to the current Code of Conduct regulations that were promulgated to provide competitive safeguards to the competitive retail electric market in Pennsylvania. The proposed changes include, but are not limited to: an EGS may not have the same or substantially similar name as the EDC or its corporate parent; EDCs and EGSs would not be permitted to share office space and would need to occupy different buildings; EDCs and affiliated EGSs could not share employees or services, except certain corporate support, emergency, or tariff services (the definition of "corporate support services" excludes items such as information systems, electronic data interchange, strategic management and planning, regulatory services, legal services, or commodities that have been included in regulated rates at less than market value); and an EGS must enter into a trademark agreement with the EDC before using its trademark or service mark. The Proposed Rulemaking Order, which was published on February 11, 2012, calls for comments to be submitted by March 27, 2012. If implemented these rules could require a significant change in the way FES, Met-Ed, Penelec, Penn and WP do business in Pennsylvania, and could possibly have an adverse impact on their results of operations and financial condition.

In November 2011, Met-Ed, Penelec, Penn and WP filed a Joint Petition for Approval of their Default Service Plan for the period June 1, 2013 through May 31, 2015. The Pennsylvania Companies' direct case was submitted in its entirety on December 20, 2011. Evidentiary hearings are scheduled for April 11-13, 2012, and a final order must be entered by the PPUC by August 17, 2012.

WEST VIRGINIA
In 2009, the West Virginia Legislature enacted the AREPA, which generally requires that a specified minimum percentage of electricity sold to retail customers in West Virginia by electric utilities each year be derived from alternative and renewable energy resources according to a predetermined schedule of increasing percentage targets, including10%by 2015,15%by 2020, and25%by 2025.


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In November 2010, the WVPSC issued RPS Rules, which became effective on January 4, 2011. Under the RPS Rules, on or before January 1, 2011, each electric utility subject to the provisions of this rule was required to prepare an alternative and renewable energy portfolio standard compliance plan and file an application with the WVPSC seeking approval of such plan. MP and PE filed their combined compliance plan in December 2010. A hearing was held at the WVPSC on June 13, 2011. An order was issued by the WVPSC in September 2011, which conditionally approved MP's and PE's compliance plan, contingent on the outcome of the resource credits case discussed below.

Additionally, in January 2011, MP and PE filed an application with the WVPSC seeking to certify three facilities as Qualified Energy Resource Facilities. The application was approved and the three facilities are capable of generating renewable credits which will assist the companies in meeting their combined requirements under the AREPA. An annual update filing is due on March 31, 2012. Further, in February 2011, MP and PE filed a petition with the WVPSC seeking an Order declaring that MP is entitled to all alternative and renewable energy resource credits associated with the electric energy, or energy and capacity, that MP is required to purchase pursuant to electric energy purchase agreements between MP and three non-utility electric generating facilities in West Virginia. The City of New Martinsville and Morgantown Energy Associates, each the owner of one of the contracted resources, has participated in the case in opposition to the Petition. A hearing was held at the WVPSC on August 25 and 26, 2011.On November 22, 2011, the WVPSC issued an order granting ownership of all RECs produced by the facilities to MP. On December 22, 2011, the WVPSC order was appealed, and the order was stayed pending the outcome of the appeal. MP's brief was filed on February 13, 2012. Should MP be unsuccessful in the appeal, it will have to procure the requisite RECs to comply with AREPA from other sources. MP expects to recover such costs from customers.

In September 2011, MP and PE filed with the WVPSC to recover costs associated with fuel and purchased power (the ENEC) in the amount of$32 millionwhich represents an approximate3%overall increase in such costs over the past two years, primarily attributable to rising coal prices. The requested increase was partially offset by$2.5 millionof synergy savings directly resulting from the merger of FirstEnergy and AE, which closed in February 2011. Under a cost recovery clause established by the WVPSC in 2007, MP and PE customer bills are adjusted periodically to reflect upward or downward changes in the cost of fuel and purchased power. The utilities' most recent request to recover costs for fuel and purchased power was in September 2009.MP and PE entered into a Settlement Agreement related to this matter. The WVPSC issued an order on December 30, 2011, approving the settlement agreement. The approved settlement resulted in an increase of$19.6 million, instead of the requested$32 million, with additional costs to be recovered over time with a carrying charge.

FERC MATTERS

PJM Transmission Rate

In April 2007, FERC issued 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, FERC directed that costs for new transmission facilities that are rated at500kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate based on the amount of load served in a transmission zone. Costs for new transmission facilities that are rated at less than500kV, however, are to be allocated on a load flow methodology, which is generally referred to as a “beneficiary pays” approach to allocating the cost of high voltage transmission facilities.

FERC's Opinion 494 order was appealed to the U.S. Court of Appeals for the Seventh Circuit, which issued a decision in August 2009. The court affirmed FERC's ratemaking treatment for existing transmission facilities, but found that FERC had not supported its decision to allocate costs for new500kV and higher voltage facilities on a load ratio share basis and, based on this finding, remanded the rate design issue to FERC.

In an order dated January 21, 2010, FERC set the matter for a “paper hearing” and requested parties to submit written comments pursuant to the schedule described in the order. FERC identifiednineseparate issues for comments and directed PJM to file the first round of comments on February 22, 2010, with other parties submitting responsive comments and then reply comments on later dates. PJM filed certain studies with FERC on April 13, 2010, in response to the FERC order. PJM's filing demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain load serving entities in PJM bearing the majority of the 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. Other utilities and state commissions supported continued socialization of these costs on a load ratio share basis. This matter is awaiting action by FERC. FirstEnergy cannot predict the outcome of this matter or estimate the possible loss or range of loss.

RTO Realignment

On June 1, 2011, ATSI and the ATSI zone entered into PJM. The move was performed as planned with no known operational or reliability issues for ATSI or for the wholesale transmission customers in the ATSI zone.

On February 1, 2011, ATSI in conjunction with PJM filed its proposal with FERC for moving its transmission rate into PJM's tariffs. On April 1, 2011, the MISO TOs (including ATSI) filed proposed tariff language that describes the mechanics of collecting and


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administering MTEP costs from ATSI-zone ratepayers. From March 20, 2011 through April 1, 2011, FirstEnergy, PJM and the MISO submitted numerous filings for the purpose of effecting movement of the ATSI zone to PJM on June 1, 2011. These filings include amendments to the MISO's tariffs (to remove the ATSI zone), submission of load and generation interconnection agreements to reflect the move into PJM, and submission of changes to PJM's tariffs to support the move into PJM.

On May 31, 2011, FERC issued orders that address the proposed ATSI transmission rate, and certain parts of the MISO tariffs that reflect the mechanics of transmission cost allocation and collection. In its May 31, 2011 orders, FERC approved ATSI's proposal to move the ATSI formula rate into the PJM tariff without significant change. Speaking to ATSI's proposed treatment of the MISO's exit fees and charges for transmission costs that were allocated to the ATSI zone, FERC required ATSI to present a cost-benefit study that demonstrates that the benefits of the move for transmission customers exceed the costs of any such move, which FERC had not previously required. Accordingly, FERC ruled that these costs must be removed from ATSI's proposed transmission rates until such time as ATSI files and FERC approves the cost-benefit study. On June 30, 2011, ATSI submitted the compliance filing that removed the MISO exit fees and transmission cost allocation charges from ATSI's proposed transmission rates. Also on June 30, 2011, ATSI requested rehearing of FERC's decision to require a cost-benefit analysis as part of FERC's evaluation of ATSI's proposed transmission rates. Finally, and also on June 30, 2011, the MISO and the MISO TOs filed a competing compliance filing - one that would require ATSI to pay certain charges related to construction and operation of transmission projects within the MISO even though FERC ruled that ATSI cannot pass these costs on to ATSI's customers. ATSI on the one hand, and the MISO and MISO TOs on the other, have submitted subsequent filings - each of which is intended to refute the other's claims. ATSI's compliance filing and request for rehearing, as well as the pleadings that reflect the dispute between ATSI and the MISO/MISO TOs, are currently pending before FERC.

From late April 2011 through June 2011, FERC issued other orders that address ATSI's move into PJM. Also, ATSI and the MISO were able to negotiate an agreement of ATSI's responsibility for certain charges associated with long term firm transmission rights that, according to the MISO, were payable by the ATSI zone upon its departure from the MISO. ATSI did not and does not agree that these costs should be charged to ATSI but, in order to settle the case and all claims associated with the case, ATSI agreed to a one-time payment of$1.8 millionto the MISO. This settlement agreement has been submitted for FERC's review and approval. The final outcome of those proceedings that address the remaining open issues related to ATSI's move into PJM and their impact, if any, on FirstEnergy cannot be predicted at this time.

MISO Multi-Value Project Rule Proposal

In July 2010, MISO and certain MISO transmission owners jointly filed with FERC their proposed cost allocation methodology for certain new transmission projects. The new transmission projects--described as MVPs - are a class of transmission projects that are approved via the MTEP. The filing parties proposed to allocate the costs of MVPs by means of a usage-based charge that will be applied to all loads within the MISO footprint, and to energy transactions that call for power to be “wheeled through” the MISO as well as to energy transactions that “source” in the MISO but “sink” outside of MISO. The filing parties expect that the MVP proposal will fund the costs of large transmission projects designed to bring wind generation from the upper Midwest to load centers in the east. The filing parties requested an effective date for the proposal of July 16, 2011. On August 19, 2010, MISO's Board approved the first MVP project -- the “Michigan Thumb Project.” Under MISO's proposal, the costs of MVP projects approved by MISO's Board prior to the June 1, 2011 effective date of FirstEnergy's integration into PJM would continue to be allocated to FirstEnergy. MISO estimated that approximately$15 millionin annual revenue requirements would be allocated to the ATSI zone associated with the Michigan Thumb Project upon its completion.

In September 2010, FirstEnergy filed a protest to the MVP proposal arguing that MISO's proposal to allocate costs of MVPs projects across the entire MISO footprint does not align with the established rule that cost allocation is to be based on cost causation (the “beneficiary pays” approach). FirstEnergy also argued that, in light of progress that had been made to date in the ATSI integration into PJM, it would be unjust and unreasonable to allocate any MVP costs to the ATSI zone, or to ATSI. Numerous other parties filed pleadings on MISO's MVP proposal.

In December 2010, FERC issued an order approving the MVP proposal without significant change. Despite being presented with the issue by FirstEnergy and the MISO, the FERC did not address clearly the question of whether the MVP costs would be payable by ATSI or load in the ATSI zone. FERC stated that the MISO's tariffs obligate ATSI to pay all charges that attached prior to ATSI's exit but ruled that the question of the amount of costs that are to be allocated to ATSI or to load in the ATSI zone were beyond the scope of FERC's order and would be addressed in future proceedings.

On January 18, 2011, FirstEnergy requested rehearing of FERC's order. In its rehearing request, FirstEnergy argued that because the MVP rate is usage-based, costs could not be applied to ATSI, which is a stand-alone transmission company that does not use the transmission system. FirstEnergy also renewed its arguments regarding cost causation and the impropriety of allocating costs to the ATSI zone or to ATSI.On October 21, 2011, FERC issued its order on rehearing, but that order did not address FirstEnergy's argument directly. FERC ruled instead that if ATSI was subject to MVP charges then ATSI owed these charges upon exit of the MISO. On October 31, 2011, FESC filed a Petition of Review for the FERC's December 2010 order and October 21, 2011 order on rehearing of that order with the U.S. Court of Appeals for the D.C. Circuit. Other parties also filed appeals of those orders and, in November, 2011, the cases were consolidated for briefing and disposition in the U.S. Court of Appeals for the Seventh Circuit. On January 27, 2012, the court ordered the FERC to file a proposed briefing format and schedule on or before March 20, 2012.



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On August 3, 2011, FirstEnergy filed a complaint with FERC based on the FERC's December 2010 order. In the complaint, FirstEnergy argued that ATSI perfected the legal and financial requirements necessary to exit MISO before any MVP responsibilities could attach and asked FERC to rule that MISO cannot charge ATSI for MVP costs. On September 2, 2011, MISO, its TOs and other parties, filed responsive pleadings. On September 19, 2011, ATSI filed an answer. On December 29, 2011, the MISO and the MISO TOs filed a new “Schedule 39” to the MISO's tariff. Schedule 39 purports to establish a process whereby the MISO would bill TOs for MVP costs that, according to the MISO, attached to the utility prior to such TOs withdrawal from the MISO. On January 19, 2012, FirstEnergy filed a protest to the MISO's new Schedule 39 tariff.

On February 27, 2012, FERC issued an order (February 2012 Order) dismissing ATSI's August 3, 2011 complaint. In the February 2012 Order, FERC accepted the MISO's Schedule 39 tariff, subject to hearings and potential refund of MVP charges to ATSI. The basis for any subsequent hearing is whether the Schedule 39 tariff was in effect at the time that ATSI exited the MISO. FirstEnergy is evaluating the February 2012 Order and will determine the next steps.

FirstEnergy cannot predict the outcome of these proceedings or estimate the possible loss or range of loss.

FirstEnergy Companies' PJM FTR Contract Underfunding Complaint

On December 28, 2011, FES and AE Supply filed a complaint with FERC against PJM challenging the ongoing underfunding of FTR contracts, which exist to hedge against transmission congestion in the day-ahead markets. The underfunding is a result of PJM's practice of using the funds that are intended to pay the holders of FTR contracts to pay instead for congestion costs that occur in the real time markets. Underfunding of the FTR contracts resulted in losses of approximately$35 millionto FES and AE Supply in the 2010-2011 Delivery Year. To date, losses for the 2011-2012 Delivery Year are estimated to be approximately$6 million.

On January 13, 2012, PJM filed comments that describe changes to the PJM tariff that, if adopted, should remedy the underfunding issue. Many parties also filed comments supporting FES' and AE Supply's position. Other parties, generally representatives of end-use customers who will have to pay the charges, filed in opposition to the complaint. The matter is currently pending before FERC. FirstEnergy cannot predict the outcome of this matter or estimate the possible loss or range of loss.

California Claims Matters

In October 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the CDWR during 2001. The settlement proposal claims that CDWR is owed approximately$190 millionfor these alleged overcharges. This proposal was made in the context of mediation efforts by FERC and the United States Court of Appeals for the Ninth Circuit in pending proceedings to resolve all outstanding refund and other claims, including claims of alleged price manipulation in the California energy markets during 2000 and 2001. The Ninth Circuit has since remandedoneof those proceedings to FERC, which arises out of claims previously filed with FERC by the California Attorney General on behalf of certain California parties against various sellers in the California wholesale power market, including AE Supply (the Lockyer case). AE Supply and several other sellers filed motions to dismiss the Lockyer case. In March 2010, the judge assigned to the case entered an opinion that granted the motions to dismiss filed by AE Supply and other sellers and dismissed the claims of the California Parties. On May 4, 2011, FERC affirmed the judge's ruling. On June 3, 2011, the California parties requested rehearing of the May 4, 2011 order. The request for rehearing remains pending.

In June 2009, the California Attorney General, on behalf of certain California parties, filed a second complaint with FERC against various sellers, including AE Supply (the Brown case), again seeking refunds for trades in the California energy markets during 2000 and 2001. The above-noted trades with CDWR are the basis for including AE Supply in this new complaint. AE Supply filed a motion to dismiss the Brown complaint that was granted by FERC on May 24, 2011. On June 23, 2011, the California Attorney General requested rehearing of the May 24, 2011 order. That request for rehearing also remains pending. FirstEnergy cannot predict the outcome of either of the above matters or estimate the possible loss or range of loss.

PATH Transmission Project

The PATH Project is comprised of a765kV transmission line that was proposed to extend from West Virginia through Virginia and into Maryland, modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland.

PJM initially authorized construction of the PATH Project in June 2007. In December 2010, PJM advised that its 2011 Load Forecast Report included load projections that are different from previous forecasts and that may have an impact on the proposed in-service date for the PATH Project. As part of its 2011 RTEP, and in response to a January 19, 2011, directive by a Virginia Hearing Examiner, PJM conducted a series of analyses using the most current economic forecasts and demand response commitments, as well as potential new generation resources. Preliminary analysis revealed the expected reliability violations that necessitated the PATH Project had moved several years into the future. Based on those results, PJM announced on February 28, 2011, that its Board of Managers had decided to hold the PATH Project in abeyance in its 2011 RTEP and directed FirstEnergy and AEP, as the sponsoring transmission owners, to suspend current development efforts on the project, subject to those activities necessary to maintain the project in its current state, while PJM conducts more rigorous analysis of the need for the project as part of its continuing RTEP


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process. PJM stated that its action did not constitute a directive to FirstEnergy and AEP to cancel or abandon the PATH Project. PJM further stated that it will complete a more rigorous analysis of the PATH Project and other transmission requirements and its Board will review this comprehensive analysis as part of its consideration of the 2011 RTEP. On February 28, 2011, affiliates of FirstEnergy and AEP filed motions or notices to withdraw applications for authorization to construct the project that were pending before state commissions in West Virginia, Virginia and Maryland. Withdrawal was deemed effective upon filing the notice with the MDPSC. The WVPSC and VSCC have granted the motions to withdraw.

PATH submitted a filing to FERC to implement a formula rate tariff effective March 1, 2008. In a November 19, 2010 order addressing various matters relating to the formula rate, FERC set the project's base ROE for hearing and reaffirmed its prior authorization of a return on CWIP, recovery of start-up costs and recovery of abandonment costs. In the order, FERC also granted a1.5%ROE incentive adder and a0.5%ROE adder for RTO participation. These adders will be applied to the base ROE determined as a result of the hearing. The PATH Companies, Joint Intervenors, Joint Consumer Advocates and FERC staff have agreed to a four year moratorium. A settlement was reached, which reflects a base ROE of10.4%(plus authorized adders) effective January 1, 2011. Accordingly, the revised ROE was reflected in a revised Projected Transmission Revenue Requirement for 2011 with true-up occurring in 2013. The FirstEnergy portion of the refund for March 1, 2008, through December 31, 2010, is approximately$2 million(inclusive of interest). The refund amount was computed using a base ROE of10.8%plus authorized adders. On October 7, 2011, PATH and six intervenors submitted to FERC an unopposed settlement agreement. Contemporaneous with this submission, PATH and the six intervenors filed with the Chief ALJ of FERC a joint motion for interim approval and authorization to implement the refund on an interim basis pending issuance of a FERC order acting on the settlement agreement. On October 12, 2011, the motion for interim approval and authorization to implement the refund was granted by the Chief ALJ. On February 16, 2012, FERC approved the settlement agreement and dismissed as moot, in light of its approval of the settlement, PATH's pending request for rehearing of the November 19, 2010 order.

Yards Creek
The Yards Creek Pumped Storage Project is a400MW hydroelectric project located in Warren County, New Jersey. JCP&L owns an undivided50%interest in the project, and operates the project. PSEG Fossil, LLC, a subsidiary of Public Service Enterprise Group, owns the remaining interest in the plant. The project was constructed in the early 1960s, and became operational in 1965. Authorization to operate the project is by a license issued by the FERC. The existing license expires on February 28, 2013.

In February 2011, JCP&L and PSEG filed a joint application with FERC to renew the license for an additional forty years. The companies are pursuing relicensure through FERC's ILP. Under the ILP, FERC will assess the license applications, issue draft and final Environmental Assessments/Environmental Impact Studies (as required by NEPA), and provide opportunities for intervention and protests by affected third parties. FERC may hold hearings during the two-year ILP licensure period. FirstEnergy expects FERC to issue the new license within the remaining portion of the two-year ILP period. To the extent, however, that the license proceedings extend beyond the February 28, 2013 expiration date for the current license, the current license will be extended yearly as necessary to permit FERC to issue the new license.
Seneca

The Seneca Pumped Storage Project is a451MW hydroelectric project located in Warren County, Pennsylvania owned and operated by FGCO. FGCO holds the current FERC license that authorizes ownership and operation of the project. The current FERC license will expire on November 30, 2015. FERC's regulations call for a five-year relicensing process. On November 24, 2010, and acting pursuant to applicable FERC regulations and rules, FGCO initiated the relicensing process by filing its notice of intent to relicense and PAD in the license docket.

On November 30, 2010, the Seneca Nation filed its notice of intent to relicense and PADs necessary for them to submit a competing application. Section 15 of the FPA contemplates that third parties may file a "competing application" to assume ownership and operation of a hydroelectric facility upon (i) relicensure and (ii) payment of net book value of the plant to the original owner/operator. Nonetheless, FGCO believes it is entitled to a statutory “incumbent preference” under Section 15.

The Seneca Nation and certain other intervenors have asked FERC to redefine the “project boundary” of the hydroelectric plant to include the dam and reservoir facilities operated by the U.S. Army Corps of Engineers. On May 16, 2011, FirstEnergy filed a Petition for Declaratory Order with FERC seeking an order to exclude the dam and reservoir facilities from the project. The Seneca Nation, the New York State Department of Environmental Conservation, and the U.S. Department of Interior each submitted responses to FirstEnergy's petition, including motions to dismiss FirstEnergy's petition. The “project boundary” issue is pending before FERC.

On September 12, 2011, FirstEnergy and the Seneca Nation each filed “Revised Study Plan” documents. These documents describe the parties' respective proposals for the scope of the environmental studies that should be performed as part of the relicensing process. On October 11, 2011, FERC Staff issued a letter order that addressed the Revised Study Plans. In the order, FERC Staff approved FirstEnergy's Revised Study Plan, subject to a finding that the Project is located on “aboriginal lands” of the Seneca Nation. Based on this finding, FERC Staff directed FirstEnergy to consult with the Seneca Nation and other parties about the data set, methodology, and modeling of the hydrological impacts of project operations. FirstEnergy is performing the work necessary to develop a study proposal from which to conduct such consultations. The study process will extend through approximately November of 2013.


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FirstEnergy cannot predict the outcome of this matter or estimate the possible loss or range of loss.
ENVIRONMENTAL MATTERS
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. Compliance with environmental regulations could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that FirstEnergy 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.
CAA Compliance
FirstEnergy is required to meet federally-approved SO2and NOx emissions regulations under the CAA. FirstEnergy complies with SO2and NOx reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, combustion controls and post-combustion controls, generating more electricity from lower or non-emitting plants and/or using emission allowances. Violations can result in the shutdown of the generating unit involved and/or civil or criminal penalties.
In July 2008,threecomplaints were filed against FGCO in the U.S. District Court for the Western District of Pennsylvania seeking damages based on air emissions from the coal-fired Bruce Mansfield Plant.Twoof these 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 oftwenty-oneindividuals and the other being a class action complaint seeking certification as a class action with theeightnamed plaintiffs as the class representatives. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these complaints.
The states of New Jersey and Connecticut filed CAA citizen suits in 2007 alleging NSR violations at the coal-fired Portland Generation Station against GenOn Energy, Inc. (formerly RRI Energy, Inc. and the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999) and Met-Ed. Specifically, these suits allege that “modifications” at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR permitting in violation of the CAA's PSD program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. In September 2009, the Court granted Met-Ed's motion to dismiss New Jersey's and Connecticut's claims for injunctive relief against Met-Ed, but denied Met-Ed's motion to dismiss the claims for civil penalties. The parties dispute the scope of Met-Ed's indemnity obligation to and from Sithe Energy, and Met-Ed is unable to predict the outcome of this matter or estimate the possible loss or range of loss.
In January 2009, the EPA issued a NOV to GenOn Energy, Inc. alleging NSR violations at the coal-fired Portland Generation Station based on “modifications” dating back to 1986. The NOV also alleged NSR violations at the Keystone and Shawville coal-fired plants based on “modifications” dating back to 1984. Met-Ed, JCP&L and Penelec are unable to predict the outcome of this matter or estimate the possible loss or range of loss.
In each of May and September 2010, New Jersey submitted interstate pollution transport petitions seeking to reduce Portland Generating Station air emissions under section 126 of the CAA. Based on the September 2010 petition, the EPA has finalized emissions limits and compliance schedules to reduce SO2air emissions by approximately 81% at the Portland Station by January 6, 2015. New Jersey's May 2010 petition is still under consideration by the EPA.
In June 2008, the EPA issued a Notice and Finding of Violation to Mission alleging that “modifications” at the coal-fired Homer City Plant occurred from 1988 to the present without preconstruction NSR permitting in violation of the CAA's PSD program. In May 2010, the EPA issued a second NOV to Mission, Penelec, NYSEG and others that have had an ownership interest in Homer City containing in all material respects allegations identical to those included in the June 2008 NOV. In January 2011, the DOJ filed a complaint against Penelec in the U.S. District Court for the Western District of Pennsylvania seeking injunctive relief against Penelec based on alleged “modifications” at Homer City between 1991 to 1994 without preconstruction NSR permitting in violation of the CAA's PSD and Title V permitting programs. The complaint was also filed against the former co-owner, NYSEG, and various current owners of Homer City, including EME Homer City Generation L.P. and affiliated companies, including Edison International. In addition, the Commonwealth of Pennsylvania and the States of New Jersey and New York intervened and have filed separate complaints regarding Homer City seeking injunctive relief and civil penalties. In January 2011, another complaint was filed against Penelec and the other entities described above in the U.S. District Court for the Western District of Pennsylvania seeking damages based on Homer City's air emissions as well as certification as a class action and to enjoin Homer City from operating except in a “safe, responsible, prudent and proper manner.” In October 2011, the Court dismissed all of the claims with prejudice of the U.S. and the Commonwealth of Pennsylvania and the States of New Jersey and New York and all of the claims of the private parties, without prejudice to re-file state law claims in state court, against all of the defendants, including Penelec.In December 2011, the U.S., the Commonwealth of Pennsylvania and the States of New Jersey and New York all filed notices appealing to the Third Circuit Court of Appeals. Penelec believes the claims are without merit and intends to defend itself against the allegations made in these complaints, but, at this time, is unable to predict the outcome of this matter or estimate the loss or possible range of loss. Mission is seeking indemnification from NYSEG and Penelec, the co-owners of Homer City prior to its sale in 1999. On February 13, 2012, the Sierra Club notified the current owner and operator of Homer City, Homer City OL1-OL8 LLC and EME Homer City Generation L.P., that it intends to file a CAA citizen suit regarding its Title V permit and SO2 emissions from the Homer City Plant.
In August 2009, the EPA issued a Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, including the


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PSD, NNSR and Title V regulations, at the Eastlake, Lakeshore, Bay Shore and Ashtabula coal-fired plants. The EPA's NOV alleges equipment replacements during maintenance outages dating back to 1990 triggered the pre-construction permitting requirements under the PSD and NNSR programs. FGCO also received a request for certain operating and maintenance information and planning information for these same generating plants and notification that the EPA is evaluating whether certain maintenance at the Eastlake Plant may constitute a major modification under the NSR provisions of the CAA. Later in 2009, FGCO also received another information request regarding emission projections for the Eastlake Plant. In June 2011, EPA issued another Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, specifically opacity limitations and requirements to continuously operate opacity monitoring systems at the Eastlake, Lakeshore, Bay Shore and Ashtabula coal-fired plants. Also, in June 2011, FirstEnergy received an information request pursuant to section 114(a) of the CAA for certain operating, maintenance and planning information, among other information regarding these plants. 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 or estimate the possible loss or range of loss.
In August 2000, AE received an information request pursuant to section 114(a) of the CAA from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the followingtencoal-fired plants, which collectively include22electric generation units: Albright, Armstrong, Fort Martin, Harrison, Hatfield's Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island to determine compliance with the NSR provisions under the CAA, which can require the installation of additional air emission control equipment when a major modification of an existing facility results in an increase in emissions. AE has provided responsive information to this and a subsequent request but is unable to predict the outcome of this matter or estimate the possible loss or range of loss.
In May 2004, AE, AE Supply, MP and WP received a Notice of Intent to Sue Pursuant to CAA §7604 from the Attorneys General of New York, New Jersey and Connecticut and from the PA DEP, alleging that Allegheny performed major modifications in violation of the PSD provisions of the CAA at the following West Virginia coal-fired generation units: Albright Unit 3; Fort Martin Units 1 and 2; Harrison Units 1, 2 and 3; Pleasants Units 1 and 2 and Willow Island Unit 2. The Notice also alleged PSD violations at the Armstrong, Hatfield's Ferry and Mitchell coal-fired plants in Pennsylvania and identifies PA DEP as the lead agency regarding those facilities. In September 2004, AE, AE Supply, MP and WP received a separate Notice of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.
In June 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed suit against AE, AE Supply, MP, PE and WP in the United States District Court for the Western District of Pennsylvania alleging, among other things, that Allegheny performed major modifications in violation of the CAA and the Pennsylvania Air Pollution Control Act at the coal-fired Hatfield's Ferry, Armstrong and Mitchell Plants in Pennsylvania. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. A non-jury trial on liability only was held in September 2010. Plaintiffs filed their proposed findings of fact and conclusions of law in December 2010, Allegheny made its related filings in February 2011 and plaintiffs filed their responses in April 2011. The parties are awaiting a decision from the District Court, but there is no deadline for that decision and we are unable to predict the outcome or estimate the possible loss or range of loss.
In September 2007, Allegheny received a NOV from the EPA alleging NSR and PSD violations under the CAA, as well as Pennsylvania and West Virginia state laws at the coal-fired Hatfield's Ferry and Armstrong plants in Pennsylvania and the coal-fired Fort Martin and Willow Island plants in West Virginia.
FirstEnergy intends to vigorously defend against the CAA matters described above but cannot predict their outcomes or estimate the possible loss or range of loss.
State Air Quality Compliance
In early 2006, Maryland passed the Healthy Air Act, which imposes state-wide emission caps on SO2and NOx, requires mercury emission reductions and mandates that Maryland join the RGGI and participate in that coalition's regional efforts to reduce CO2emissions. On April 20, 2007, Maryland became the tenth state to join the RGGI. The Healthy Air Act provides a conditional exemption for the R. Paul Smith coal-fired plant for NOx, SO2and mercury, based on a 2006 PJM declaration that the plant is vital to reliability in the Baltimore/Washington DC metropolitan area. Pursuant to the legislation, the MDE passed alternate NOx and SO2limits for R. Paul Smith, which became effective in April 2009. However, R. Paul Smith is still required to meet the Healthy Air Act mercury reductions of80%which began in 2010. The statutory exemption does not extend to R. Paul Smith's CO2emissions. Maryland issued final regulations to implement RGGI requirements in February 2008.FourteenRGGI auctions have been held through the end of calendar year 2011. RGGI allowances are also readily available in the allowance markets, affording another mechanism by which to secure necessary allowances. On March 14, 2011, MDE requested PJM perform an analysis to determine if termination of operation at R. Paul Smith would adversely impact the reliability of electrical service in the PJM region under current system conditions. On June 30, 2011, PJM notified MDE that termination of operation at R. Paul Smith would adversely impact the reliability of electrical service in the PJM region absent transmission system upgrades. On January 26, 2012, FirstEnergy announced that R. Paul Smith is among nine coal-fired plants it intends to retire by September 1, 2012, subject to review of reliability impacts by PJM. FirstEnergy is unable to predict the outcome of this matter or estimate the possible loss or range of loss.
In January 2010, the WVDEP issued a NOV for opacity emissions at the Pleasants coal-fired plant. In August 2011, FirstEnergy and WVDEP resolved the NOV through a Consent Order requiring installation of a reagent injection system to reduce opacity by September 2012.


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National Ambient Air Quality Standards
The EPA's CAIR requires reductions of NOx and SO2emissions intwophases (2009/2010 and 2015), ultimately capping SO2emissions in affected states to2.5 milliontons annually and NOx emissions to1.3 milliontons annually. In 2008, the U.S. Court of Appeals for the District of Columbia vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” In December 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 opinion. The Court ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOx SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the “8-hour” ozone NAAQS. In July 2011, the EPA finalized the CSAPR, to replace CAIR,requiring reductions of NOx and SO2emissions intwo phases (2012 and 2014), ultimately capping SO2emissions in affected states to2.4 milliontons annually and NOx emissions to1.2 milliontons annually. CSAPR allows trading of NOx and SO2emission allowances between power plants located in the same state and interstate trading of NOx and SO2emission allowances with some restrictions. On February 21, 2012, the EPA revised certain CASPR state budgets (for Florida, Louisiana, Michigan, Mississippi, Nebraska, New Jersey, New York, Texas, and Wisconsin and new unit set-asides in Arkansas and Texas), certain generating unit allocations (for some units in Alabama, Indiana, Kansas, Kentucky, Ohio and Tennessee) for NOx and SO2emissions and delayed from 2012 to 2014 certain allowance penalties that could apply with respect to interstate trading of NOx and SO2emission allowances.On December 30, 2011, CSAPR was stayed by the U.S. Court of Appeals for the District of Columbia Circuit pending a decision on legal challenges raised in appeals filed by various stakeholders and scheduled to be argued before the Court on April 13, 2012. The Court ordered EPA to continue administration of CAIR until the Court resolves the CSAPR appeals. Depending on the outcome of these proceedings and how any final rules are ultimately implemented, FGCO's and AE Supply's future cost of compliance may be substantial and changes to FirstEnergy's operations may result.

During 2011, FirstEnergy recorded pre-tax impairment charges of approximately$6 million($1 millionfor FES and$5 millionfor AE Supply) for NOx emission allowances that were expected to be obsolete after 2011 and approximately$21 million($18 millionfor FES and$3 millionfor AE Supply) for excess SO2emission allowances in inventory that it expects will not be consumed in the future.
Hazardous Air Pollutant Emissions
On December 21, 2011, the EPA finalized the MATS to establish emission standards for mercury, hydrochloric acid and various metals for electric generating units. The MATS establishes emission limits for mercury, PM, and HCL for all existing and new coal-fired electric generating units effective in April 2015 and allows averaging of emissions from multiple units located at a single plant. Under the CAA, state permitting authorities can grant an additional compliance year through April 2016, as needed, including instances when necessary to maintain reliability where electric generating units are being closed. In addition, an EPA enforcement policy document contemplates up to an additional year to achieve compliance, through April 2017, under certain circumstances for reliability critical units. On January 26, 2012 and February 8, 2012, FGCO, MP and AE Supply announced the retirement by September 1, 2012 (subject to a reliability review by PJM) of nine coal-fired power plants (Albright, Armstrong, Ashtabula, Bay Shore except for generating unit 1, Eastlake, Lake Shore, R. Paul Smith, Rivesville and Willow Island) with a total capacity of3,349megawatts (generating, on average, approximately ten percent of the electricity produced by the companies over the past three years) due to MATS and other environmental regulations. In addition, MP will make a filing with the WVPSC to provide them with information regarding the retirement of its plants. Depending on how the MATS are ultimately implemented, FirstEnergy's future cost of compliance with MATS may be substantial and other changes to FirstEnergy's operations may result.
On February 24, 2012, PJM notified FirstEnergy of its preliminary analysis of the reliability impacts that may result from closure of the older competitive coal-fired generating units. PJM's preliminary analysis indicated that there would be significant reliability concerns that will need to be addressed. FirstEnergy intends to continue to actively engage in discussions with PJM regarding this notification, including the possible continued operation of certain plants.
Climate Change
There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. 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, in June 2009. Certain states, primarily the northeastern states participating in the RGGI and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.
In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that required FirstEnergy to measure and report GHG emissions commencing in 2010. In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA's finding concludes that concentrations of several key GHGs increase the threat of climate change and may be regulated as “air pollutants” under the CAA. In April 2010, the EPA finalized new 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 would not be triggered for electric generating plants and other stationary sources until January 2, 2011, at the earliest. In May 2010, the EPA finalized new thresholds for GHG emissions that define when permits under the CAA's NSR program would be required. The EPA established an emissions applicability threshold of75,000tons per year of CO2equivalents effective January 2, 2011, for existing facilities under the CAA's PSD program.


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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 man-made GHG, including CO2, emitted by developed countries by 2012. A December 2009 U.N. Climate Change Conference in Copenhagen did not reach a consensus on a successor treaty to the Kyoto Protocol, but did take note of the Copenhagen Accord, a non-binding political agreement that recognized the scientific view that the increase in global temperature should be belowtwodegrees Celsius; includes a commitment by developed countries to provide funds, approaching$30 billionover three years with a goal of increasing to$100 billionby 2020; and establishes the “Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. To the extent that 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 targets from 2020, while developing countries, including Brazil, China and India, would agree to take mitigation actions, subject to their domestic measurement, reporting and verification.A December 2011 U.N. Climate Change Conference in Durban, Africa, established a negotiating process to develop a new post-2020 climate change protocol, called the “Durban Platform for Enhanced Action”. This negotiating process contemplates developed countries, as well as developing countries such as China, India, Brazil, and South Africa, to undertake legally binding commitments post-2020. In addition, certain countries agreed to extend the Kyoto Protocol for a second commitment period, commencing in 2013 and expiring in 2018 or 2020.
In 2009, the U.S. Court of Appeals for the Second Circuit and 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. 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. The U.S. Supreme Court granted a writ of certiorari to review the decision of the Second Circuit. On June 20, 2011, the U.S. Supreme Court reversed the Second Circuit but failed to answer the question of the extent to which actions for damages based on GHG emissions may remain viable. The Court remanded to the Second Circuit the issue of whether the CAA preempted state common law nuisance actions.
FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO2emissions per KWH of electricity generated by FirstEnergy is lower than many of its regional competitors due to its diversified generation sources, which include low or non-CO2emitting gas-fired and nuclear generators.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal CWA and its amendments, apply to FirstEnergy's plants. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy's operations.
In 2004, the EPA established new performance standards under Section 316(b) of the CWA for reducing impacts on fish and shellfish from cooling water intake structures at certain existing electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). In 2007, the Court of Appeals for the Second Circuit invalidated portions of the Section 316(b) performance standards and the EPA has taken the position 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. In April 2009, the U.S. Supreme Court reversed one significant aspect of the Second Circuit's opinion and decided that Section 316(b) of the CWA authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. On March 28, 2011, the EPA released a new proposed regulation under Section 316(b) of the CWA generally requiring fish impingement to be reduced to a12%annual average and studies to be conducted at the majority of our existing generating facilities to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic life. On July 19, 2011, the EPA extended the public comment period for the new proposed Section 316(b) regulation by30days but stated its schedule for issuing a final rule remains July 27, 2012. FirstEnergy is studying various control options and their costs and 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. 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.
In April 2011, the U.S. Attorney's Office in Cleveland, Ohio advised FGCO that it is no longer considering prosecution under the CWA 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. On August 5, 2011, EPA issued an information request pursuant to Sections 308 and 311 of the CWA for certain information pertaining to the oil spills and spill prevention measures at FirstEnergy facilities. FirstEnergy responded on October 10, 2011. On February 1, 2012, FirstEnergy executed a tolling agreement with the EPA extending the statute of limitations to July 31, 2012. FGCO does not anticipate any losses resulting from this matter to be material.
In May 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club filed a CWA citizen suit alleging violations of arsenic limits in the NPDES water discharge permit for the fly ash impoundments at the Albright Station seeking unspecified civil penalties and injunctive relief. The MP filed an answer on July 11, 2011, and a motion to stay the proceedings


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on July 13, 2011. On January 3, 2012, the Court denied MP's motion to dismiss or stay the CWA citizen suit but without prejudice to re-filing in the future. MP is currently seeking relief from the arsenic limits through WVDEP agency review.
In June 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club served a60-Day Notice of Intent required prior to filing a citizen suit under the CWA for alleged failure to obtain a permit to construct the fly ash impoundments at the Albright Plant.
FirstEnergy intends to vigorously defend against the CWA matters described above but, except as indicated above, cannot predict their outcomes or estimate the possible loss or range of loss.
Monongahela River Water Quality
In late 2008, the PA DEP imposed water quality criteria for certain effluents, including TDS and sulfate concentrations in the Monongahela River, on new and modified sources, including the scrubber project at the coal-fired Hatfield's Ferry Plant. These criteria are reflected in the current PA DEP water discharge permit for that project. AE Supply appealed the PA DEP's permitting decision, which would require it to incur estimated costs in excess of$150 millionin order to install technology to meet TDS and sulfate limits in the permit or negatively affect its ability to operate the scrubbers as designed. The permit has been independently appealed by Environmental Integrity Project and Citizens Coal Council, which seeks to impose more stringent technology-based effluent limitations. Those same parties have intervened in the appeal filed by AE Supply, and both appeals have been consolidated for discovery purposes. An order has been entered that stays the permit limits that AE Supply has challenged while the appeal is pending. A hearing on the parties' appeals was scheduled to begin in September 2011, however the Court stayed all prehearing deadlines on July 15, 2011 to allow the parties additional time to work out a settlement, and has rescheduled a hearing, if necessary, for July 2012. If these settlement discussions are successful, AE Supply anticipates that its obligations will not be material. AE Supply intends to vigorously pursue these issues, but cannot predict the outcome of these appeals or estimate the possible loss or range of loss.
In a parallel rulemaking, the PA DEP recommended, and in August 2010, the Pennsylvania Environmental Quality Board issued, a final rule imposing end-of-pipe TDS effluent limitations. FirstEnergy could incur significant costs for additional control equipment to meet the requirements of this rule, although its provisions do not apply to electric generating units until the end of 2018, and then only if the EPA has not promulgated TDS effluent limitation guidelines applicable to such units.
In December 2010, PA DEP submitted its CWA 303(d) list to the EPA with a recommended sulfate impairment designation for an approximately68mile stretch of the Monongahela River north of the West Virginia border. In May 2011, the EPA agreed with PA DEP's recommended sulfate impairment designation. PA DEP's goal is to submit a final water quality standards regulation, incorporating the sulfate impairment designation for EPA approval by May, 2013. PA DEP will then need to develop a TMDL limit for the river, a process that will take approximatelyfiveyears. Based on the stringency of the TMDL, FirstEnergy may incur significant costs to reduce sulfate discharges into the Monongahela River from the coal-fired Hatfield's Ferry and Mitchell Plants in Pennsylvania and the coal-fired Fort Martin Plant in West Virginia.
In October 2009, the WVDEP issued the water discharge permit for the Fort Martin Plant. Similar to the Hatfield's Ferry water discharge permit, the Fort Martin permit imposes effluent limitations for TDS and sulfate concentrations. The permit also imposes temperature limitations and other effluent limits for heavy metals that are not contained in the Hatfield's Ferry water discharge permit. Concurrent with the issuance of the Fort Martin permit, WVDEP also issued an administrative order that sets deadlines for MP to meet certain of the effluent limits that are effective immediately under the terms of the permit. MP appealed the Fort Martin permit and the administrative order. The appeal included a request to stay certain of the conditions of the permit and order while the appeal is pending, which was granted pending a final decision on appeal and subject to WVDEP moving to dissolve the stay. The appeals have been consolidated. MP moved to dismiss certain of the permit conditions for the failure of the WVDEP to submit those conditions for public review and comment during the permitting process. An agreed-upon order that suspends further action on this appeal, pending WVDEP's release for public review and comment on those conditions, was entered on August 11, 2010. The stay remains in effect during that process. The current terms of the Fort Martin permit would require MP to incur significant costs or negatively affect operations at Fort Martin. Preliminary information indicates an initial capital investment in excess of the capital investment that may be needed at Hatfield's Ferry in order to install technology to meet the TDS and sulfate limits in the Fort Martin permit, which technology may also meet certain of the other effluent limits in the permit. Additional technology may be needed to meet certain other limits in the permit. MP intends to vigorously pursue these issues but cannot predict the outcome of these appeals or estimate the possible loss or range of loss.
Regulation of Waste Disposal
Federal 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. Certain fossil-fuel combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. In February 2009, the EPA requested comments from the states on options for regulating coal combustion residuals, including whether they should be regulated as hazardous or non-hazardous waste.
In December 2009, in an advance notice of public rulemaking, the EPA asserted that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. In May 2010, the EPA proposedtwooptions for additional


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regulation of coal combustion residuals, including the option of regulation as a special waste under the EPA's hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. FirstEnergy's future cost of compliance with any coal combustion residuals regulations that 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. Compliance with those regulations could have an adverse impact on FirstEnergy's results of operations and financial condition.
LBR CCB impoundment is expected to run out of disposal capacity for disposal of CCBs from the BMP between 2016 and 2018. BMP is pursuing several CCB disposal options.
Certain of our 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 ofDecember 31, 2011, based on estimates of the total costs of cleanup, the Utility Registrants' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay.Total liabilities of approximately$106 million(JCP&L -$70 million, TE -$1 million, CEI -$1 million, FGCO -$1 millionand FE -$33 million) have been accrued throughDecember 31, 2011. Included in the total are accrued liabilities of approximately$63 millionfor 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. On July 11, 2011, FirstEnergy was found to be a potentially responsible party under CERCLA, indirectly liable for a portion of past and future clean-up costs at certain legacy MGP sites, estimated to total approximately$59 million. FirstEnergy recognized an additional expense of$29 millionduring the second quarter of 2011;$30 millionhad previously been reserved prior to 2011.FirstEnergy determined that it is reasonably possible that it or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the possible losses or range of losses cannot be determined or reasonably estimated at this time.
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.Twoclass action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages due to the outages. After various motions, rulings and appeals, the Plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, strict product liability and punitive damages were dismissed, leaving only the negligence and breach of contract causes of actions. On July 29, 2010, the Appellate Division upheld the trial court's decision decertifying the class. In November 2010, the Supreme Court issued an order denying Plaintiffs' motion for leave to appeal. The Court's order effectively ends the attempt to certify the class, and leaves only9plaintiffs to pursue their respective individual claims. The matter was referred back to the lower court, which set a trial date for February 13, 2012, for the remaining individual plaintiffs. Plaintiffs have accepted an immaterial amount in final settlement of all matters and the settlement documentation is being finalized for execution by all parties.
Nuclear Plant Matters
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As ofDecember 31, 2011, FirstEnergy had approximately$2 billioninvested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy's NDT fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy's obligation to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the NDT. On March 28, 2011, FENOC submitted its biennial report on nuclear decommissioning funding to the NRC. This submittal identified a total shortfall in nuclear decommissioning funding for Beaver Valley Unit 1 and Perry of approximately$92.5 million. By letter dated December 29, 2011, FENOC informed the NRC staff that it had increased the parental guarantee to$95 million.
In January 2004, subsidiaries of FirstEnergy filed a lawsuit in the U.S. Court of Federal Claims seeking damages in connection with costs incurred at the Beaver Valley, Davis-Besse and Perry nuclear facilities as a result of the DOE's failure to begin accepting spent nuclear fuel on January 31, 1998. DOE was required to begin accepting spent nuclear fuel by the Nuclear Waste Policy Act (42 USC 10101 et seq) and the contracts entered into by the DOE and the owners and operators of these facilities pursuant to the Act.In January 2012, the applicable FirstEnergy affiliates reached a$48 millionsettlement of these claims.

In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse operating license for an additional twenty years, until 2037. By an order dated April 26, 2011, a NRC ASLB granted a hearing on the Davis-Besse license renewal application to a group of petitioners. By this order, the ASLB also admitted two contentions challenging whether FENOC's Environmental Report adequately evaluated (1) a combination of renewable energy sources as alternatives to the renewal of Davis-Besse's operating license, and (2) severe accident mitigation alternatives at Davis-Besse. On May 6, 2011, FENOC filed an appeal with the NRC from the order granting a hearing on the Davis-Besse license renewal application.On January 10, 2012, intervenors petitioned the ASLB for a new contention on the cracking of the Davis-Besse shield building discussed below.


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On October 1, 2011, Davis-Besse was safely shut down for a scheduled outage to install a new reactor vessel head and complete other maintenance activities. The new reactor head, which replaced a head installed in 2002, enhances safety and reliability, and features control rod nozzles made of material less susceptible to cracking. On October 10, 2011, following opening of the building for installation of the new reactor head, a sub-surface hairline crack was identified in one of the exterior architectural elements on the shield building. These elements serve as architectural features and do not have structural significance. During investigation of the crack at the shield building opening, concrete samples and electronic testing found similar sub-surface hairline cracks in most of the building's architectural elements. FENOC's investigation also identified other indications. Included among them were sub-surface hairline cracks in the upper portion of the shield building (above elevation 780') and in the vicinity of the main steam line penetrations.A team of industry-recognized structural concrete experts and Davis-Besse engineers has determined these conditions do not affect the facility's structural integrity or safety.
On December 2, 2011, the NRC issued a CAL which concluded that FENOC provided "reasonable assurance that the shield building remains capable of performing its safety functions." The CAL imposed a number of commitments from FENOC including, submitting a root cause evaluation and corrective actions to the NRC by February 28, 2012, and further evaluations of the shield building. On February 27, 2012, FENOC sent the root cause evaluation to the NRC. Finally, the CAL also stated that the NRC was still evaluating whether the current condition of the shield building conforms to the plant's licensing basis. On December 6, 2011, the Davis-Besse plant returned to service.
By letter dated August 25, 2011, the NRC made a final significance determination (white) associated with a violation that occurred during the retraction of a source range monitor from the Perry reactor vessel. The NRC also placed Perry in the degraded cornerstone column (Column 3) of the NRC's Action Matrix governing the oversight of commercial nuclear reactors. As a result, the NRC staff will conduct several supplemental inspections, culminating in an inspection using Inspection Procedure 95002 to determine if the root cause and contributing causes of risk significant performance issues are understood, the extent of condition has been identified, whether safety culture contributed to the performance issues, and if FENOC's corrective actions are sufficient to address the causes and prevent recurrence.
In light of the impacts of the earthquake and tsunami on the reactors in Fukushima, Japan, the NRC conducted inspections of emergency equipment at U.S. reactors. The NRC also established a Near-Term Task Force to review its processes and regulations in light of the incident, and, on July 12, 2011, the Task Force issued its report of recommendations for regulatory changes. On October 18, 2011, the NRC approved the Staff recommendations, and directed the Staff to implement its near-term recommendations without delay. Ultimately, the adoption of the Staff recommendations on near-term actions is likely to result in additional costs to implement plant modifications and upgrades required by the regulatory process over the next several years, which costs are likely to be material.
On February 16, 2012, the NRC issued a request for information to the licensed operators of 11 nuclear power plants, including Beaver Valley Power Station Units 1 and 2, with respect to the modeling of fuel performance as it relates to "thermal conductivity degradation," which is the potential in older fuel for reduced capacity to transfer heat that could potentially change its performance during various accident scenarios, including loss of coolant accidents. The request for information indicated that this phenomenon has not been accounted for adequately in performance models for the fuel developed by the fuel manufacturer. The NRC is requesting that FENOC provide an analysis to demonstrate that the NRC regulations are being met. Absent that demonstration, the request indicates that the NRC may consider imposing restrictions on reactor operating limits until the issue is satisfactorily resolved.
ICG Litigation
On December 28, 2006, AE Supply and MP filed a complaint in the Court of Common Pleas of Allegheny County, Pennsylvania against ICG, Anker WV, and Anker Coal. Anker WV entered into a long term Coal Sales Agreement with AE Supply and MP for the supply of coal to the Harrison generating facility. Prior to the time of trial, ICG was dismissed as a defendant by the Court, which issue can be the subject of a future appeal. As a result of defendants' past and continued failure to supply the contracted coal, AE Supply and MP have incurred and will continue to incur significant additional costs for purchasing replacement coal. A non-jury trial was held from January 10, 2011 through February 1, 2011. At trial, AE Supply and MP presented evidence that they have incurred in excess of$80 millionin damages for replacement coal purchased through the end of 2010 and will incur additional damages in excess of$150 millionfor future shortfalls. Defendants primarily claim that their performance is excused under a force majeure clause in the coal sales agreement and presented evidence at trial that they will continue to not provide the contracted yearly tonnage amounts. On May 2, 2011, the court entered a verdict in favor of AE Supply and MP for$104 million($90 millionin future damages and$14 millionfor replacement coal / interest). Post-trial filings occurred in May 2011, with Oral Argument on June 28, 2011. On August 25, 2011, the Allegheny County Court denied all Motions for Post-Trial relief and the May 2, 2011 verdict became final. On August 26, 2011, ICG posted bond and filed a Notice of Appeal. Briefing on the Appeal is concluded with oral argument expected in May or June of 2012. AE Supply and MP intend to vigorously pursue this matter through appeal.

Other Legal Matters

In February 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 reduction 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 approved by the PUCO. In March 2010, the named-defendant companies filed a motion to dismiss the case due to the lack of jurisdiction of the court of common


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pleas. The court granted the motion to dismiss on September 7, 2010. The plaintiffs appealed the decision to the Court of Appeals of Ohio.On October 21, 2011, the Court of Appeals rendered its decision affirming the dismissal of the Complaint by the Court of Common Pleas on all counts except for one relating to an allegation of fraud. The Companies timely filed a notice of appeal on December 5, 2011 with the Supreme Court of Ohio challenging this one aspect of the Court of Appeals opinion. The Supreme Court of Ohio has not yet acted on the appeal.

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 15, Regulatory Matters.

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. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss and if such estimate can be made. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced above, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
FirstEnergy prepares consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. FirstEnergy's accounting policies require significant judgment regarding estimates and assumptions underling the amounts included in the financial statements. Additional information regarding the application of accounting policies are included in the Combined Notes to the Consolidated Financial Statements.
Revenue Recognition
FirstEnergy follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled sales is recognized. The determination of unbilled sales and revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, demand by customer class, applicable billing demands, weather-related impacts, number of days unbilled and tariff rates in effect within each customer class.
Regulatory Accounting
FirstEnergy’s regulated distribution and regulated independent transmission segments are subject to regulations that sets the prices (rates) the Utilities, ATSI, TrAIL and PATH are permitted to charge customers based on costs that the regulatory agencies determine are permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This ratemaking process results in the recording of regulatory assets and liabilities based on anticipated future cash inflows and outflows. FirstEnergy regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future.
Pensions and OPEB Accounting
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 provides a portion of non-contributory pre-retirement basic life insurance for employees who are eligible to retire. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.
As described in Note 1, Organization, Basis of Presentation and Significant Accounting Policies, FirstEnergy elected to change its method of recognizing actuarial gains and losses for its defined benefit pension plans and OPEB plans effective in 2011. Previously, FirstEnergy recognized the net actuarial gains and losses as a component of AOCI and amortized the gains and losses into income over the remaining service life of affected employees within the related plans, to the extent such gains and losses were outside a corridor of the greater of 10% of the market-related value of plan assets or 10% of the plans' projected benefit obligation.

FirstEnergy has elected to immediately recognize the change in the fair value of plan assets and net actuarial gains and losses annually in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. The remaining components of pension and OPEB expense, primarily service, interest, assumed return on assets and prior service costs, will be recorded on a quarterly basis.


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FirstEnergy's funding policy is based on actuarial computations using the projected unit credit method. During 2011, FirstEnergy made pre-tax contributions to its qualified pension plans of $372 million. FirstEnergy made an additional $600 million pre-tax contribution to its qualified pension plan on January 5, 2012. The underfunded status of FirstEnergy’s qualified and non-qualified pension and OPEB plans as of December 31, 2011 was $2.6 billion.
As a result of the merger with AE in 2011, FirstEnergy assumed certain pension and OPEB plans. FirstEnergy measured the funded status of the Allegheny pension plans and OPEB plans as of the merger closing date using discount rates of 5.50% and 5.25%, respectively. The fair values of plan assets for Allegheny's pension plans and OPEB plans at the date of the merger were $954 million and $75 million, respectively, and the actuarially determined benefit obligations for such plans as of that date were $1,341 million and $272 million, respectively. The expected returns on plan assets used to calculate net periodic costs for periods in 2011 subsequent to the date of the merger are 8.25% for Allegheny's qualified pension plan and 5.00% for Allegheny's OPEB plans.
In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and OPEB obligations. The assumed discount rates for pensions were 5.00%, 5.50% and 6.00% as of December 31, 2011, 2010 and 2009, respectively. The assumed discount rates for OPEB were 4.75%, 5.00% and 5.75% as of December 31, 2011, 2010 and 2009, respectively.
FirstEnergy’s assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by the pension trusts. In 2011, FirstEnergy’s qualified pensions and OPEB plan assets earned $387 million or 6.05% compared to amounts earned of $492 million, or 10.1% in 2010. The qualified pension and OPEB costs in 2011 and 2010 were computed using an assumed 8.25% and 8.50% rate of return, respectively, on plan assets which generated $486 million and $397 million of expected returns on plan assets, respectively. The expected return of pensions and OPEB assets is based on the trusts’ asset allocation targets and the historical performance of risk-based and fixed income securities. The gains or losses generated as a result of the difference between expected and actual returns on plan assets will increase or decrease future net periodic pension and OPEB cost as the difference is recognized annually in the fourth quarter of each fiscal year.
Based on discounts rates of 5.00% for pension, 4.75% for OPEB and an estimated return on assets of 7.75%, FirstEnergy expects its 2012 pre-tax net periodic postemployment benefit credits (including amounts capitalized) to be approximately $117 million (excluding any actuarial mark-to-market adjustments that would be recognized in 2012). The following table reflects the portion of pensions and OPEB costs that were charged to expense in the three years ended December 31, 2011.
Postemployment Benefits Expense (Credits) 2011 2010 2009
  (In millions)
Pensions $555
 $247
 $377
OPEB (112) (126) (57)
Total $443
 $121
 $320
Health care cost trends continue to increase and will affect future OPEB costs. The 2011 composite health care trend rate assumptions were approximately 7.5-8.5%, compared to 8.0-9.0% in 2010, gradually decreasing to 5% in later years. In determining FirstEnergy’s trend rate assumptions, included are the specific provisions of FirstEnergy’s health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in FirstEnergy’s health care plans, and projections of future medical trend rates. The effect on the pension and OPEB costs from changes in key assumptions are as follows:
Increase in Net Periodic Benefit Costs from Adverse Changes in Key Assumptions
Assumption Adverse Change Pensions OPEB Total
      (In millions)  
Discount rate Decrease by 0.25% $236
 $23
 $259
Long-term return on assets Decrease by 0.25% $16
 $1
 $17
Health care trend rate Increase by 1.0% N/A
 $27
 $27
Emission Allowances
FirstEnergy holds emission allowances for SO2 and NOx in order to comply with programs implemented by the EPA designed to regulate emissions of SO2 and NOx produced by power plants. Emission allowances are either granted by the EPA at zero cost or are purchased at fair value as needed to meet emission requirements. Emission allowances are not purchased with the intent of resale. Emission allowances eligible to be used in the current year are recorded in materials and supplies inventory at their weighted average cost. Emission allowances eligible for use in future years are recorded as other investments. FirstEnergy recognizes emission allowance costs as fuel expense during the periods that emissions are produced by generating facilities. Emission allowances that are not needed to meet emission requirements may be sold and are reported as a reduction to other operating expenses. Obsolete or excess emission allowances follow FirstEnergy's inventory practice that requires the emission allowances to be recorded at the lower of weighted average cost or market value. See Note 11, Impairment of Long-Lived Assets for further information on impairments of emission allowances.


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Long-Lived Assets
FirstEnergy reviews long-lived assets, including regulatory assets, for impairment whenever events or changes in circumstances indicate that the carrying amount of such an asset may not be recoverable. The recoverability of the long-lived asset is measured by comparing the long-lived asset’s carrying value to the sum of undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is greater than the undiscounted future cash flows of the long-lived asset, impairment exists and a loss is recognized for the amount by which the carrying value of the long-lived asset exceeds its estimated fair value. Impairments of long-lived assets recognized for the year endedDecember 31, 2011, are described further in Note 11, Impairment of Long-Lived Assets.
Asset Retirement Obligations
FirstEnergy recognizes an ARO for the future decommissioning of its nuclear power plants and future remediation of other environmental liabilities associated with all of its long-lived assets. The ARO liability represents an estimate of the fair value of FirstEnergy’s current obligation related to nuclear decommissioning and the retirement or remediation of environmental liabilities of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. FirstEnergy uses an expected cash flow approach to measure the fair value of the nuclear decommissioning and environmental remediation ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plant’s current license, settlement based on an extended license term and expected remediation dates. The fair value of an ARO is recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and are depreciated over the life of the related asset.
Income Taxes
FirstEnergy records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to temporary tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled.
FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. We account for uncertain income tax positions using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being ultimately realized upon ultimate settlement. If it is not more likely than not that the benefit will be sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. The Company recognizes interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized and the amount previously taken or expected to be taken on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes.
Goodwill
In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Goodwill is evaluated for impairment at least annually and more frequently if indicators of impairment arise. In accordance with accounting standards, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. Impairment is indicated and a loss is recognized if the implied fair value of a reporting unit’s goodwill is less than the carrying value of its goodwill.
NEW ACCOUNTING PRONOUNCEMENTS
See Note 1, Organization, Basis of Presentation and Significant Accounting Policies for discussion of new accounting pronouncements.


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FIRSTENERGY SOLUTIONS CORP.
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
FES is a wholly owned subsidiary of FirstEnergy. FES provides energy-related products and services to wholesale and retail customers, and through its principal subsidiaries, FGCO and NGC, owns or leases, operates and maintains FirstEnergy’s fossil and hydroelectric generation facilities (excluding the Allegheny facilities), and owns, through its subsidiary, NGC, FirstEnergy’s nuclear generation facilities, respectively. FENOC, a wholly owned subsidiary of FirstEnergy, operates and maintains the nuclear generating facilities. FES purchases the entire output of the generation facilities owned by FGCO and NGC, as well as the output relating to leasehold interests of OE and TE in certain of those facilities that are subject to sale and leaseback arrangements with non-affiliates, and pursuant to full output, cost-of-service PSAs.
FES’ revenues are derived from sales to individual retail customers, sales to communities in the form of governmental aggregation programs, and participation in affiliated and non-affiliated POLR auctions. FES’ sales are primarily concentrated in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland. In 2010, FES also supplied the POLR default service requirements of Met-Ed and Penelec.
The demand for electricity produced and sold by FES, along with the price of that electricity, is principally impacted by conditions in competitive power markets, global economic activity, economic activity in the Midwest and Mid-Atlantic regions and weather conditions.
For additional information with respect to FES, 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: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies, Outlook and New Accounting Pronouncements.
Results of Operations
Net income decreased by $290 million in 2011 compared to 2010. The decrease was primarily due to higher operating expenses, an inventory reserve adjustment and the effect of mark-to-market adjustments, partially offset by lower non-core asset impairment charges.
Revenues
Total revenues decreased $351 million, or 6%, in 2011 compared to 2010, primarily due to reduced POLR and structured sales, partially offset by growth in direct and governmental aggregation sales.
The net decrease in total revenues resulted from the following sources:
Revenues by Type of Service 2011 2010 
Increase
(Decrease)
  (In millions)
Direct and Governmental Aggregation $3,785
 $2,493
 $1,292
POLR and Structured Sales 944
 2,589
 (1,645)
Wholesale 457
 397
 60
Transmission 108
 77
 31
RECs 67
 74
 (7)
Sale of OVEC participation interest —
 85
 (85)
Other 116
 113
 3
Total Revenues $5,477
 $5,828
 $(351)
MWH Sales by Type of Service 2011 2010 
Increase
(Decrease)
  (In thousands)  
Direct 46,187
 28,499
 62.1 %
Governmental Aggregation 17,722
 12,796
 38.5 %
POLR and Structured Sales 15,340
 50,358
 (69.5)%
Wholesale 2,916
 5,391
 (45.9)%
Total Sales 82,165
 97,044
 (15.3)%


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The increase in direct and governmental aggregation revenues of $1.3 billion resulted from the acquisition of new residential, commercial and industrial customers, as well as new governmental aggregation contracts with communities in Ohio and Illinois that provide generation to approximately 1.8 million residential and small commercial customers at the end of 2011 compared to approximately 1.5 million customers at the end of 2010. Increases in direct sales volume were partially offset by lower unit prices.
The decrease in POLR and structured sales revenues of $1.6 billion was due to lower sales volumes to Met-Ed, Penelec and the Ohio Companies, partially offset by increased sales to non-affiliates and higher unit prices to the Pennsylvania Companies. The decline in POLR sales reflects our focus on more profitable sales channels.
Wholesale revenues increased $60 million due to higher wholesale prices partially offset by decreased volumes. The lower sales volumes were the result of decreased short-term (net hourly positions) transactions in MISO, partially offset by increased short-term transactions in PJM. In addition, capacity revenues earned by units that moved to PJM from MISO were partially offset by losses on financially settled sales contracts.
The following tables summarize the price and volume factors contributing to changes in revenues from generation sales:
Source of Change in Direct and Governmental Aggregation Increase(Decrease)
  (In millions)
Direct Sales:  
Effect of increase in sales volumes $1,034
Change in prices (75)
  959
Governmental Aggregation:  
Effect of increase in sales volumes 319
Change in prices 14
  333
Increase in Direct and Government Aggregation Revenues $1,292
Source of Change in POLR and Structured Revenues Increase (Decrease)
  (In millions)
   
Effect of decrease in sales volumes $(1,800)
Change in prices 155
  $(1,645)
   
Source of Change in Wholesale Revenues Increase (Decrease)
  (In millions)
   
Effect of decrease in sales volumes $(182)
Change in prices 242
  $60
Transmission revenues increased $31 million due primarily to higher congestion revenue. Revenues derived from the sale of RECs decreased $7 million in 2011 compared to 2010.
Operating Expenses
Total operating expenses decreased by $34 million in 2011 compared with the 2010.


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The following table summarizes the factors contributing to the changes in fuel and purchased power costs in 2011 compared with 2010:
Source of Change in Fuel and Purchased Power Increase (Decrease)
  (In millions)
Fossil Fuel:  
Change due to increased unit costs $26
Change due to volume consumed (107)
  (81)
   
Nuclear Fuel:  
Change due to increased unit costs 28
Change due to volume consumed (6)
  22
   
Non-affiliated Purchased Power:  
Change due to increased unit costs 416
Change due to volume purchased (623)
  (207)
   
Affiliated Purchased Power:  
Change due to decreased unit costs (84)
Change due to volume purchased (45)
  (129)
Net Decrease in Fuel and Purchased Power Costs $(395)

Total fuel costs decreased by $59 million in 2011 compared to the same period of 2010, as a result of reduced generation at the fossil units, partially offset by higher fossil unit costs. Fossil unit costs increased primarily due to increased coal transportation costs. Nuclear fuel expenses increased primarily due to higher unit prices following the refueling outages that occurred in 2010.
Non-affiliated purchased power costs decreased by $217 million in 2011 compared to the same period of 2010, due to lower volumes purchased, partially offset by higher unit costs. The decrease in volume relates to the absence in 2011 of a 1,300 MW third-party contract associated with serving Met-Ed and Penelec that FES no longer has the requirement to serve. Affiliated purchased power costs decreased by $119 million in 2011, compared to the same period of 2010, due to lower unit costs and decreased volumes purchased.
Other operating expenses increased by $400 million in 2011 compared to the same period of 2010 due to the following:

Transmission expenses increased by $249 million due primarily to increases in congestion, network and line loss expenses.
Nuclear operating costs increased $53 million primarily due to Perry and Beaver Valley Unit 2 refueling outages in 2011. While Davis-Besse had a refueling outage in 2010 and an outage in 2011 to replace the reactor vessel head, the work performed on both outages was largely capital-related.
Fossil operating costs increased $36 million due primarily to higher labor, contractor and material costs resulting from an increase in planned and unplanned outages, which were partially offset by reduced losses from the sale of excess coal.
A $54 million provision for excess and obsolete material related to revised inventory practices adopted in connection with the Allegheny merger.
Pensions and OPEB mark-to-market adjustment charges increased $64 million as a result of higher net actuarial losses.
Impairment charges on long-lived assets decreased by $94 million compared to 2010. The 2011 charges were due to the pending shutdown of four coal-fired generating units owned by FGCO; charges in 2010 related to operational changes at certain smaller coal-fired units.
General taxes increased by $30 million due to an increase in revenue-related taxes.
Provision for depreciation increased by $29 million due to the AQC projects being placed in service at the end of 2010.


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Other Expense
Total other expense increased by $41 million in 2011, compared to 2010, primarily due to a $57 million decrease in capitalized interest associated with the completion of the Sammis AQC project in 2010, partially offset by lower interest expense ($5 million).
Market Risk Information
FES uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.
Commodity Price Risk
FES is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. FirstEnergy's Risk Policy 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 practice. FES uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.
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, FES relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FES uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making.making (see Note 9, Fair Value Measurements of the Combined Notes to the Consolidated Financial Statements). Sources of information for the valuation of commodity derivative contractscontract assets and liabilities as of December 31, 2011, are summarized by year are summarized in the following table:
Source of Information               
- Fair Value by Contract Year
 
2010
 
2011
 
2012
 
2013
 
2014
 
Thereafter
 
Total
 
Source of Information-
Fair Value by Contract Year
 2012 2013 2014 2015 2016 Thereafter Total
 (In millions)  (In millions)
Prices actively quoted(1)
  $(11) $-  $-  $-  $-  $-  $(11) $—
 $—
 $—
 $—
 $—
 $—
 $—
Other external sources(2)
   (111)  (98)  -   -   -   -   (209) (15) 11
 20
 8
 —
 —
 24
Prices based on models (6) —
 —
 —
 (2) (8) (16)
Total  $(122) $(98) $-  $-  $   $-  $(220) $(21) $11
 $20
 $8
 $(2) $(8) $8
(1)
Represents exchange traded New York Mercantile Exchange traded.futures and options.
(2)
Broker quote sheets.Primarily represents contracts based on broker and IntercontinentalExchange quotes.

FES 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 FES’ derivative instruments would not have had a material effect on its consolidated financial position (assets, liabilities and equity) or cash flows as of December 31, 2009. Based on derivative contracts held as of December 31, 2009,2011, an adverse 10% change in commodity prices would decrease net income by approximately $9$7 million forduring the next 12 months.

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Interest Rate Risk

FES’ exposure to fluctuations in market interest rates is reduced since a significant portion of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for FES’ investment portfolio and debt obligations.

Comparison of Carrying Value to Fair ValueComparison of Carrying Value to Fair Value Comparison of Carrying Value to Fair Value
                There-     Fair 
Year of Maturity 2010  2011  2012  2013  2014  after  Total  Value  2012 2013 2014 2015 2016 There-after Total Fair Value
 (Dollars in millions)  (In millions)
Assets
                        
Investments Other Than Cash
                        
and Cash Equivalents:
                        
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income
 $11              $1,043  $1,054  $1,057            $1,025
 $1,025
 $1,025
Average interest rate
  2.8%              4.4%  4.4%               6.5% 6.5%  
                            
Liabilities
                            
Liabilities:                
Long-term Debt:
                                            
Fixed rate
 $53  $58  $68  $75  $99  $1,888  $2,241  $2,290  $68
 $75
 $99
 $450
 $26
 $2,445
 $3,163
 $3,419
Average interest rate
  9.0%  8.9%  9.0%  9.0%  7.3%  6.0%  6.4%     9.0% 9.0% 7.3% 5.1% 7.7% 5.1% 5.4%  
Variable rate
                     $1,983  $1,983  $2,016            $512
 $512
 $512
Average interest rate
                      1.8%  1.8%               0.1% 0.1%  
Short-term Borrowings:
 $109                      $109  $109 
Average interest rate
  1.8%                      1.8%    


Fluctuations106


Equity Price Risk
NDT funds have been established to satisfy NGC’s nuclear decommissioning obligations. Included in the fair valueFES’s NDT are fixed income, equities and short-term investments carried at market values of NGC's decommissioning trust balances will eventually affect earnings (immediately for other-than-temporary impairmentsapproximately $1,025 million, $124 million and affecting OCI initially for unrealized gains) based on authoritative guidance. As$132 million, respectively, as of December 31, 2009, NGC’s2011, excluding ($58) million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $12 million reduction in fair value as of December 31, 2011. NGC recognized in earnings the unrealized losses on available-for-sale securities held in their NDT as OTTI. A decline in the value of FES’s NDT or a significant escalation in estimated decommissioning trust balance totaled $1.1 billion, comprised primarily of debt instruments.

costs could result in additional funding requirements.
Credit Risk

Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. FES evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. FES may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. FES monitors the financial conditions of existing counterparties on an obligor's failure to meetongoing basis. An independent risk management group oversees credit risk.
Wholesale Credit Risk
FES measures wholesale credit risk as the terms of any investment contract, loan agreement or otherwise perform as agreed. Credit risk arises from all activitiesreplacement cost for derivatives in which success depends on issuer, borrower or counterparty performance, whether reflected on or off the balance sheet. FES engages in transactions for the purchase and sale of commodities includingpower, natural gas, electricity, coal and emission allowances. These transactions are often with majorallowances, adjusted for amounts owed to or due from counterparties for settled transactions. The replacement cost of open positions represents unrealized gains, net of any unrealized losses, where FES has a legally enforceable right of setoff. FES monitors and manages the credit risk of wholesale marketing, risk management and energy companies within the industry.

FES maintainstransacting operation through credit policies with respect to our counterparties to manage overalland procedures, which include an established credit risk. This includes performing independent risk evaluations, activelyapproval process, daily monitoring portfolio trends and usingof counterparty credit limits, the use of credit mitigation measures such as margin, collateral and contract provisions to mitigate exposure. As partthe use of its credit program,master netting agreements. FES aggressively manages the quality of its portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB (S&P). As
Retail Credit Risk
FES is exposed to retail credit risk through competitive electricity activities, which serve residential, commercial and industrial companies. Retail credit risk results when customers default on contractual obligations or fail to pay for service rendered. This risk represents the loss that may be incurred due to the nonpayment of December 31, 2009,customer accounts receivable balances, as well as the largestloss from the resale of energy previously committed to serve customers.
Retail credit concentration was with AEP, whichrisk is currently rated investment grade, representing 8.9%managed through established credit approval policies, monitoring customer exposures and the use of FES’ total approved credit risk.mitigation measures such as deposits in the form of letters of credit, cash or prepayment arrangements.
Retail credit quality is dependent on the economy and the ability of customers to manage through unfavorable economic cycles and other market changes. If the business environment were to be negatively affected by changes in economic or other market conditions, FES's retail credit risk may be adversely impacted.


107

110

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


OE is a wholly owned electric utility subsidiary of FirstEnergy. OE engages in the distribution and sale of electric energy to communities in a 7,000 square mile area of central and northeastern Ohio and, through its wholly owned subsidiary, Penn, 1,100 square miles in western Pennsylvania. OE and Penn conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. They provideservices and procurement of generation services tofor those franchise customers electing to retain OE and Pennthem as their power supplier. Until December 31, 2008,The areas served by OE 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 the Combined Notes to the Consolidated Financial Statements for a discussionPenn have populations of Ohio power supply procurement issues for 2009approximately 2.3 million and beyond.

0.4 million, respectively.
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: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Guarantees and Other Assurances, Strategy and Outlook,Contractual Obligations, Off-Balance Sheet Arrangements, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.

Results of Operations

Earnings availableNet income decreased by $27 million in 2011 compared to parent decreased to $122 million in 2009 from $212 million in 2008.2010. The decrease primarily resulted from lower electric sales revenues and higher purchased power costs,other operating expenses, partially offset by a decrease in other operatinglower purchased power costs.

Revenues

Revenues decreased by $85$203 million, or 3.3%11%, in 20092011 compared to 2008, primarilywith 2010 due to decreases in distribution throughput and transmissionlower retail generation revenues, partially offset by increaseshigher distribution and wholesale generation revenues.
Distribution revenues increased by $69 million in generation revenues.

Revenues from distribution throughput decreased by $262 million in 20092011, compared to 20082010, due to lowerincreased MWH deliveries and higher average unit prices and lower KWH deliveries toin all customer classes. Milder weather-influenced usageThe higher MWH deliveries in 2009 contributed to the decreased KWH sales to residential customers (heating degree days decreased 3.3% and 1.4% and cooling degree days decreasedclass were driven primarily by 16.5% and 6.1%increased load growth partially offset by lower weather-related usage. The increase in OE’s and Penn’s service territories, respectively). Reduceddistribution deliveries to commercial and industrial customers reflectwas primarily due to recovering economic conditions in OE’s and Penn’s service territories. Higher average prices in all customer classes were principally due to the weakened economy. Transition charges that ceased effective January 1, 2009, with the full recovery of related costs, were partially offset by a July 2008 increase to a PUCO-approved transmission rider and a January 2009deferred distribution rate increase (see Regulatory Matters – Ohio).costs.

Changes in distribution KWHMWH deliveries and revenues in 20092011 compared to 20082010, are summarized in the following tables.tables:

Distribution KWHMWH Deliveries DecreaseIncrease
   
Residential 0.3(2.8)%
Commercial 0.7(4.2)%
Industrial 5.4(21.4)%
DecreaseIncrease in Distribution Deliveries 2.0(9.6)%

Distribution Revenues Increase
  (In millions)
Residential $26
Commercial 17
Industrial 26
Increase in Distribution Revenues $69

Distribution Revenues Decrease 
  (In millions) 
Residential $(45)
Commercial  (98)
Industrial  (119)
Decrease in Distribution Revenues $(262)

Transmission revenues decreased $27 million in 2009 as compared to 2008 due to the elimination of transmission revenues as part of the generation rate established under OE's CBP, effective June 1, 2009.

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Retail generation revenues increased $92decreased by $277 million primarily due to highera decrease in MWH sales from increased customer shopping and lower average prices. The higher prices in all customer classes. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. OE and Penn defer the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings. Lower MWH sales were partially offset by decreases in KWH sales, reflectingprimarily the impactresult of increased customer shopping in the fourth quarter of 2009. Reduced2011. The increases in shopping by residential, commercial and industrial customers were 18%, 11%and commercial KWH sales also reflected weakened economic conditions. Average prices increased primarily due to an increase7%, respectively, in OE's fuel cost recovery rider that was effective from January through May 2009. Effective June 1, 2009, the transmission tariff ended and the recovery of transmission costs is included in the generation rate established under OE’s CBP.2011 compared with 2010.


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Decreases in retail generation MWH sales and revenues in 20092011 compared to 20082010 are summarized in the following tables:
Retail Generation KWHMWH Sales Decrease
   
Residential (0.128.8)%
Commercial (1.534.0)%
Industrial (27.922.6)%
Decrease in Retail Generation Sales (9.228.3)%

Retail Generation Revenues Decrease
  (In millions)
Residential $(166)
Commercial (74)
Industrial (37)
Decrease in Retail Generation Revenues $(277)

Retail Generation Revenues - Changes 
Increase
(Decrease)
 
  (In millions) 
Residential $56 
Commercial  49 
Industrial  (13)
Net Increase in Generation Revenues $92 
Wholesale generation revenues increased by $116$12 million primarilyin 2011 compared to 2010 due to higher average unit prices that were partially offsetrevenues from sales to NGC from OE’s leasehold interests in Perry Unit 1 and Beaver Valley Unit 2.
Operating Expenses
Total operating expenses decreased by a slight decrease$175 million in sales volume.

Expenses

Total expenses increased by $20 million in 20092011 compared to 2008.2010. The following table presents changes from the prior year by expense category.category:
Operating Expenses - Changes Increase (Decrease)
  (In millions)
Purchased power costs $(279)
Other operating expenses 109
Pensions and OPEB mark-to-market adjustment 19
Provision for depreciation 2
Amortization of regulatory assets, net (33)
General taxes 7
Net Decrease in Operating Expenses $(175)

Expenses – Changes 
Increase
(Decrease)
 
  (In millions) 
Purchased power costs $154 
Other operating costs  (105)
Provision for depreciation  10 
Amortization of regulatory assets, net  (24)
General taxes  (15)
Net Increase in Expenses $20 
Purchased power costs decreased in 2011 compared to 2010 due to lower MWH purchases resulting from reduced generation sales requirements coupled with lower unit costs. The increase in other operating expenses in 2011 compared to the same period of 2010 was principally due to expenses associated with nuclear refueling outages at OE’s leased Perry Unit 1 and Beaver Valley Unit 2 that were absent in 2010. Decreased pensions and OPEB mark-to-market adjustment charges are the result of lower net actuarial losses in 2011 compared to 2010. The amortization of regulatory assets decreased primarily due to higher deferred residential generation credits in 2011. General taxes increased as a result of higher property taxes.
Interest Rate Risk
OE’s exposure to fluctuations in market interest rates is reduced since all of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for OE’s investment portfolio and debt obligations.


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Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income $31
 $36
 $42
 $37
 $13
 $138
 $297
 $318
Average interest rate 8.7% 8.8% 8.8% 8.9% 8.9% 4.4% 6.8%  
Liabilities:                
Long-term Debt:                
Fixed rate       $150
 $250
 $757
 $1,157
 $1,434
Average interest rate       5.5% 6.4% 7.3% 6.9%  
Equity Price Risk
NDT funds have been established to satisfy nuclear decommissioning obligations. Included in OE’s NDT are fixed income and short-term investments carried at market values of approximately $134 million and $1 million, respectively, as of December 31, 2011, excluding $2 million of net receivables, payables and accrued income. OE recognizes in earnings the unrealized losses on available-for-sale securities held in its NDT as OTTI. A decline in the value of OE's NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During 2011, approximately $4 million was contributed to OE's NDT to comply with requirements under certain sale-leaseback transactions in which OE continues as a lessee.
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. OE evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. OE may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. OE monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.


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THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI provides regulated electric distribution services in an area of 1,600 square miles in northeastern Ohio. The area it serves has a population of approximately 1.7 million. CEI also procures generation services for those customers electing to retain them 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: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Contractual Obligations, Off-Balance Sheet Arrangements, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
On January 25, 2012, CEI filed a Form 15 with the SEC to deregister its securities and suspend its obligation to file periodic reports under the Securities Exchange Act of 1934, as amended, except that the registrant has filed this Annual Report on Form 10-K for the year ended December 31, 2011. This Annual Report on Form 10-K will be the last filing made by CEI with the SEC under the Exchange Act.
Results of Operations
Earnings available to parent decreased by $5 million in 2011 compared to 2010. The decrease in earnings was primarily due to decreased revenues, partially offset by lower purchased power costs reflectand amortization of regulatory assets.
Revenues
Revenues decreased $345 million, or 28%, in 2011 compared to 2010 due to lower retail generation and distribution revenues.
Distribution revenues decreased $78 million in 2011 compared to 2010 due to lower average unit prices in all customer classes offset by increased MWH deliveries to the resultsindustrial sector. The lower average unit prices were the result of OE’sthe absence of transition charges in 2011. Lower residential and commercial deliveries resulted from decreased weather-related usage in 2011. In the industrial sector, MWH deliveries increased primarily as a result of recovering economic conditions in CEI's service territory.
Changes in distribution MWH deliveries and revenues in 2011 compared to 2010 are summarized in the following tables:
Distribution MWH DeliveriesIncrease (Decrease)
Residential(0.3)%
Commercial(0.4)%
Industrial1.4 %
Net Increase in Distribution Deliveries0.2 %
Distribution Revenues Decrease
  (In millions)
Residential $(12)
Commercial (7)
Industrial (59)
Decrease in Distribution Revenues $(78)
Retail generation revenues decreased $265 million in 2011 as compared to 2010 primarily due to lower MWH sales to all customer classes that resulted from increased customer shopping and lower average unit prices for the commercial and residential customer classes. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. CEI defers the difference between retail generation revenues and purchased power procurement processcosts, resulting in no material effect to current period earnings. Lower MWH sales were the result of increased shopping by residential, commercial and industrial customers of 15%, 8% and 36%, respectively, in 2011 compared to 2010. Lower average unit prices in the residential customer class were primarily due to the lower auction price in 2011.


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Changes in retail generation sales and revenues in 2011 compared to 2010 are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(38.8)%
Commercial(37.6)%
Industrial(71.3)%
Decrease in Retail Generation Sales(52.2)%
Retail Generation Revenues Decrease
  (In millions)
Residential $(88)
Commercial (77)
Industrial (100)
Decrease in Retail Generation Revenues $(265)
Operating Expenses
Total operating expenses decreased $336 million in 2011 compared to 2010. The following table presents changes from the prior year by expense category:
Operating Expenses - Changes 
Increase
(Decrease)
  (In millions)
Purchased power costs $(254)
Other operating costs 15
Pensions and OPEB mark-to-market adjustment 8
Provision for depreciation 1
Amortization of regulatory assets, net (117)
General taxes 11
Net Decrease in Operating Expenses $(336)
Purchased power costs decreased in 2011 primarily due to lower MWH purchases resulting from reduced sales requirements as a result of increased customer shopping. Other operating expenses increased due to 2011 inventory valuation adjustments. Increased pensions and OPEB mark-to-market adjustment changes were due to higher net actuarial losses in 2011 as compared to 2010. Amortization of regulatory assets decreased primarily due to the completion of transition cost recovery at the end of 2010 and higher deferred purchased power costs in 2011, partially offset by increased recovery of deferred distribution costs and the absence in 2011 of renewable energy credit expenses that were deferred in 2010. General taxes increased due to increased property taxes as compared to 2010.
Interest Rate Risk
CEI's exposure to fluctuations in market interest rates is reduced since all of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for retailCEI’s investment portfolio and debt obligations.


112


Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income $66
 $75
 $80
 $50
 $16
   $287
 $315
Average interest rate 7.7% 7.7% 7.7% 7.7% 8.0%   7.7%  
Liabilities:                
Long-term Debt:                
Fixed rate   $325
 $26
 $24
 $6
 $1,450
 $1,831
 $2,162
Average interest rate   5.8% 7.7% 7.7% 7.7% 6.8% 6.7%  
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. CEI evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. CEI may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. CEI monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.


113


THE TOLEDO EDISON COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
TE is a wholly owned electric utility subsidiary of FirstEnergy. TE provides regulated electric distribution services in an area of 2,300 square miles in northwestern Ohio. The area it serves has a population of approximately 0.7 million. TE also provides generation services to those customers electing to retain them as their power supplier.
For additional information with respect to TE, please see the information contained in 2009 (seeFirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Contractual Obligations, Off-Balance Sheet Arrangements, Regulatory Matters, – Ohio).Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
On January 25, 2012, TE filed a Form 15 with the SEC to deregister its securities and suspend its obligation to file periodic reports under the Securities Exchange Act of 1934, as amended, except that the registrant has filed this Annual Report on Form 10-K for the year ended December 31, 2011. This Annual Report on Form 10-K will be the last filing made by TE with the SEC under the Exchange Act.
Results of Operations
Earnings available to parent decreased by $2 million in 2011 compared to 2010. The decrease was primarily from lower revenues and higher other operating expenses, partially offset by lower purchased power costs from affiliates.
Revenues
Revenues decreased $40 million, or 8%, in 2011 compared to 2010, primarily due to lower retail generation sales, partially offset by an increase in distribution revenues.
Distribution revenues increased $28 million in 2011 compared to 2010, primarily due to higher MWH deliveries to residential and industrial customers and higher unit prices to all customer classes related to increased energy efficiency rider rates, partially offset by lower MWH deliveries to commercial customers. Higher MWH deliveries to residential customers reflected increased load growth slightly offset by lower weather-related usage that also drove lower deliveries to commercial customers. In the industrial sector, MWH deliveries increased primarily as a result of recovering economic conditions in TE's service territory.
Changes in distribution MWH deliveries and revenues in 2011 compared to 2010 are summarized in the following tables:
Distribution MWH DeliveriesIncrease (Decrease)
Residential0.3 %
Commercial(1.9)%
Industrial2.4 %
Net Increase in Distribution Deliveries1.0 %
Distribution Revenues Increase
  (In millions)
Residential $11
Commercial 9
Industrial 8
Increase in Distribution Revenues $28
Retail generation revenues decreased $79 million in 2011 compared to 2010, primarily due to lower MWH sales from increased customer shopping and lower unit prices to all customer classes. The increases in shopping for residential, commercial and industrial customers were 13%, 9%, and 4%, respectively, in 2011 compared with 2010. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. TE defers the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings.


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Decreases in retail generation MWH sales and revenues in 2011 compared to 2010 are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(27.9)%
Commercial(39.7)%
Industrial(10.1)%
Decrease in Retail Generation Sales(20.5)%
Retail Generation Revenues Decrease
  (In millions)
Residential $(28)
Commercial (21)
Industrial (30)
Decrease in Retail Generation Revenues $(79)
Wholesale revenues increased $12 million in 2011 compared to 2010, primarily due to higher revenues from sales to NGC from TE’s leasehold interest in Beaver Valley Unit 2.
Operating Expenses
Total operating expenses decreased $37 million in 2011 compared to 2010. The following table presents changes from the prior year by expense category:
Operating Expenses - Changes Increase (Decrease)
  (In millions)
Purchased power costs $(76)
Other operating expenses 31
Pensions and OPEB mark-to-market adjustment 6
General taxes 2
Net Decrease in Operating Expenses $(37)
Purchased power costs decreased in 2011 compared to 2010, due to lower MWH purchases resulting from reduced generation sales requirements in 2011 coupled with lower unit costs. The increase in other operating costs in 2011 was primarily due to expenses associated with the 2011 nuclear refueling outage at the leased Beaver Valley Unit 2 and an Ohio Supreme Court decision rendered in the second quarter of 2011 favoring a large industrial customer, both of which were absent in 2010. Increased pensions and OPEB mark-to-market adjustment charges were due to higher net actuarial losses in 2011 as compared to 2010.
Other Expense
Other expense decreased slightly in 2011 compared to 2010, due to a decrease in miscellaneous expense partially offset by lower investment income. The change in miscellaneous expense was due to decreased expenses associated with the accounts receivable securitization with Centerior Funding Corp., which was terminated in 2011 Investment income decreased principally due to lower NDT investment income.
Interest Rate Risk
TE's exposure to fluctuations in market interest rates is reduced since all of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for 2009TE’s investment portfolio and debt obligations.


115


Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income   $25
 $26
 $24
 $6
 $53
 $134
 $145
Average interest rate   7.7% 7.7% 7.7% 7.7% 4.6% 6.4%  
Liabilities:                
Long-term Debt:                
Fixed rate           $600
 $600
 $741
Average interest rate           6.7% 6.7%  
Equity Price Risk
NDT funds have been established to satisfy nuclear decommissioning obligations. Included in TE’s NDT are fixed income, equities and short-term investments carried at market values of approximately $53 million, $27 million and $3 million, respectively, as of December 31, 2011. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $3 million reduction in fair value as of December 31, 2011. TE recognizes in earnings the unrealized losses on available-for-sale securities held in their NDT as OTTI. A decline in the value of TE’s NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During 2011, approximately $1 million was contributed to TE's NDT to comply with requirements under certain sale-leaseback transactions in which TE continues as a lessee.
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. TE evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. TE may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. TE monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.


116


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 in 3,200 square miles of northern, western and east central New Jersey. The area it serves has a population of approximately 2.7 million. JCP&L also has an ownership interest in a hydroelectric generating facility. In addition, JCP&L also procures generation services for franchise customers electing to retain them 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: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Contractual Obligations, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
Results of Operations
Net income decreased by $39 million in 2011 compared to 2010. The decrease was primarily due to lower transmission expenses (included in the cost of power purchased from others beginning June 1, 2009),revenues, partially offset by reductions in purchased power costs associatedand amortization of regulatory assets.
Revenues
Revenues decreased by $532 million, or 18%, in 2011 compared to 2010. The decrease in revenues was due to lower distribution, retail generation and wholesale generation revenues, partially offset by an increase in other revenues.
Distribution revenues decreased by $187 million in 2011, compared to 2010, primarily due to an NJBPU-approved rate adjustment that became effective March 1, 2011 for all customer classes, and lower MWH deliveries. The lower MWH deliveries to residential customers were influenced by decreased weather-related usage in 2011. Lower distribution deliveries to commercial and industrial customers reflected the impact of economic conditions in JCP&L's service territory.
Decreases in distribution MWH deliveries and revenues in 2011 compared to 2010 are summarized in the following tables:
Distribution MWH DeliveriesDecrease
Residential(3.0)%
Commercial(2.9)%
Industrial(3.0)%
Decrease in Distribution Deliveries(2.9)%
Distribution Revenues Decrease
  (In millions)
Residential $(90)
Commercial (79)
Industrial (18)
Decrease in Distribution Revenues $(187)

Retail generation revenues decreased by $301 million due to lower generation MWH sales in all customer classes primarily due to an increase in customer shopping. The increases in shopping for residential, commercial and industrial customers were 10%, 9% and 5%, respectively, in 2011 compared with 2010. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. JCP&L defers the difference between retail generation revenues and purchased power costs, resulting in no material effect to earnings.


117


Decreases in retail generation MWH sales and revenues in 2011, compared to 2010, are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(13.0)%
Commercial(23.0)%
Industrial(29.0)%
Decrease in Retail Generation Sales(16.3)%
Retail Generation Revenues Decrease
  (In millions)
Residential $(181)
Commercial (108)
Industrial (12)
Decrease in Retail Generation Revenues $(301)

Wholesale generation revenues decreased by $54 million in 2011, compared to 2010, due to a decrease in PJM spot market energy sales.
Other revenues increased by $10 million in 2011, compared to 2010, primarily due to increases in PJM network transmission revenues and transition bond revenues from increased rates.
Operating Expenses
Total operating expenses decreased by $461 million in 2011 compared to 2010. The following table presents changes from the prior year by expense category:
Operating Expenses - Changes Increase (Decrease)
  (In millions)
Purchased power costs $(354)
Other operating expenses 48
Pensions and OPEB mark-to-market adjustment 34
Provision for depreciation 22
Amortization of regulatory assets, net (213)
General taxes 2
Net Decrease in Operating Expenses $(461)

Purchased power costs decreased by $354 million in 2011 due to lower requirements from reduced retail generation sales. Other operating expenses increased by $48 million in 2011 principally from storm restoration maintenance costs. Increased pensions and OPEB mark-to-market adjustment changes were due to higher net actuarial losses in 2011 as compared to 2010. Amortization of regulatory assets, net, decreased by $213 million due to reduced cost recovery under the NJBPU-approved NUG tariffs that became effective March 1, 2011 and higher deferred storm restoration costs, partially offset by a charge for nonrecoverable NUG costs.
Market Risk Information
JCP&L uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.
Commodity Price Risk
JCP&L is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas and energy transmission. FirstEnergy's Risk Policy 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 practice. JCP&L uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.
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, JCP&L relies on model-based information. The model provides estimates of future


118


regional prices for electricity and an estimate of related price volatility. JCP&L uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making (see Note 9, Fair Value Measurements of the Combined Notes to the Consolidated Financial Statements). Sources of information for the valuation of commodity derivative contract assets and liabilities as of December 31, 2011, are summarized by year in the following table:
Source of Information-
Fair Value by Contract Year
 2012 2013 2014 2015 2016 Thereafter Total
  (In millions)
Prices actively quoted(1)
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Other external sources(2)
 (52) (43) (36) (14) —
 —
 (145)
Prices based on models —
 —
 —
 —
 1
 1
 2
Total(3)
 $(52) $(43) $(36) $(14) $1
 $1
 $(143)
(1)
Represents exchange traded New York Mercantile Exchange futures and options.
(2)
Primarily represents contracts based on broker and IntercontinentalExchange quotes.
(3)
Includes $(143) million in non-hedge commodity derivative contracts that are related to NUG contracts. NUG contracts are subject to regulatory accounting and do not materially impact earnings.
JCP&L performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. Based on derivative contracts held as of December 31, 2011, an adverse 10% change in commodity prices would not have a material effect on JCP&L’s net income for the next 12 months.
Interest Rate Risk
JCP&L’s exposure to fluctuations in market interest rates is reduced since all of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for JCP&L’s investment portfolio and debt obligations.
Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income           $363
 $363
 $363
Average interest rate           5.2% 5.2%  
Liabilities:                
Long-term Debt:                
Fixed rate $34
 $36
 $38
 $41
 $343
 $1,285
 $1,777
 $2,080
Average interest rate 5.7% 5.7% 5.9% 6.0% 5.7% 6.2% 6.1%  
Equity Price Risk
NDT funds have been established to satisfy nuclear decommissioning obligations. Included in JCP&L’s NDT are fixed income, equities and short-term investments carried at market values of approximately $147 million, $30 million and $14 million, respectively, as of December 31, 2011, excluding $2 million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $3 million reduction in fair value as of December 31, 2011. JCP&L's NDT is 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. A decline in the value of JCP&L's NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During 2011, approximately $1 million was contributed to JCP&L's NDT to comply with regulatory obligationsrequirements.
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. JCP&L evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. JCP&L may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. JCP&L monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.


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METROPOLITAN EDISON COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
Met-Ed is a wholly owned electric utility subsidiary of FirstEnergy. Met-Ed provides regulated electric transmission and distribution services in 3,300 square miles of eastern and south central Pennsylvania. The area it serves has a population of approximately 1.2 million. Met-Ed also procures generation service for economic developmentthose franchise customers who have elected to retain them as their power supplier. Met-Ed procures power under its DSP, in which full requirements products (energy, capacity, ancillary services, and energy efficiency programsapplicable transmission services) are procured through descending clock auctions.
For additional information with respect to Met-Ed, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under OE’s ESP. Higher depreciation expensethe following subheadings: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Contractual Obligations, Off-Balance Sheet Arrangements, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
On January 25, 2012, Met-Ed filed a Form 15 with the SEC to deregister its securities and suspend its obligation to file periodic reports under the Securities Exchange Act of 1934, as amended, except that the registrant has filed this Annual Report on Form 10-K for the year ended December 31, 2011. This Annual Report on Form 10-K will be the last filing made by Met-Ed with the SEC under the Exchange Act.
Results of Operations
Net income increased by $8 million in 2009 reflected capital additions since the end of 2008. Lower2011 compared to 2010. The increase was primarily due to decreased purchased power costs, other operating expenses and amortization of net regulatory assets waspartially offset by decreased revenues.
Revenues
Revenue decreased $606 million, or 33%, in 2011 compared to 2010, reflecting lower distribution, retail generation, wholesale generation and transmission revenues.
Distribution revenues decreased $336 million in 2011 compared to 2010, primarily due to lower rates resulting from the DSP that began in 2011 that eliminated the transmission component from the distribution rates. The lower MWH deliveries to residential and commercial customers were influenced by decreased weather-related usage in 2011. In the industrial sector, MWH deliveries increased primarily as a result of recovering economic conditions in Met-Ed's service territory.
Changes in distribution MWH deliveries and revenues in 2011 compared to 2010 are summarized in the following tables:
Distribution MWH DeliveriesIncrease (Decrease)
Residential(1.4)%
Commercial(2.0)%
Industrial2.2 %
Net Decrease in Distribution Deliveries(0.2)%
Distribution Revenues Decrease
  (In millions)
Residential $(133)
Commercial (90)
Industrial (113)
Decrease in Distribution Revenues $(336)
In 2011, retail generation revenues decreased $52 million due to lower MWH sales to all customer classes resulting from increased customer shopping. The impact of increased customer shopping is partially offset by higher generation rates that reflect the inclusion of transmission services under the DSP, effective January 1, 2011, for all customer classes. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. In 2011, Met-Ed began deferring the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings.


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Changes in retail generation MWH sales and revenues in 2011 compared to 2010 are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(3.8)%
Commercial(49.1)%
Industrial(91.8)%
Net Decrease in Retail Generation Sales(45.7)%
Retail Generation Revenues Increase (Decrease)
  (In millions)
Residential $166
Commercial (24)
Industrial (194)
Net Decrease in Retail Generation Revenues $(52)
Wholesale revenues decreased $210 million in 2011 compared to 2010, primarily reflecting lower RPM revenues for Met-Ed in the PJM market.
Transmission revenues decreased $9 million in 2011 compared to 2010 primarily due to the conclusiontermination of Met-Ed’s TSC rates effective January 1, 2011. Met-Ed deferred the difference between transmission revenues and transmission costs incurred, resulting in no material effect to earnings in the period.
Operating Expenses
Total operating expenses decreased $608 million in 2011 compared to 2010. The following table presents changes from the prior year by expense category:
Operating Expenses - Changes Increase (Decrease)
  (In millions)
Purchased power costs $(328)
Other operating costs (230)
Pensions and OPEB mark-to-market adjustment 26
Provision for depreciation 5
Amortization of regulatory assets, net (68)
General taxes (13)
Net Decrease in Operating Expenses $(608)
Purchased power costs decreased $328 million in 2011 compared to 2010 due to a decrease in MWH purchased to source generation sales requirements, partially offset by higher unit costs. Decreased power purchased from affiliates reflects the increase in customer shopping described above and the termination of Met-Ed's partial requirements PSA with FES at the end of 2010. Other operating costs decreased $230 million in 2011 compared to 2010 due to lower transmission congestion and transmission loss expenses that are now included in the cost of purchased power (see reference to deferral accounting above), partially offset by increased costs for energy efficiency programs. Increased pensions and OPEB mark-to-market adjustment changes were due to higher net actuarial losses in 2011 as compared to 2010. The amortization of regulatory assets decreased $68 million in 2011 compared to 2010 primarily due to the termination of transmission and transition cost amortizationtariff riders at the end of 2010. General taxes decreased by $13 million in 2011 primarily due to lower gross receipts taxes.
Other Expense
Interest income decreased by $3 million in 2011 compared to 2010 primarily due to reduced CTC stranded asset balances.
Market Risk Information
Met-Ed uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.


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Commodity Price Risk
Met-Ed is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas and energy transmission. FirstEnergy's Risk Policy 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 practice. Met-Ed uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.
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, Met-Ed relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Met-Ed uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making (see Note 9, Fair Value Measurements of the Combined Notes to the Consolidated Financial Statements). Sources of information for the valuation of commodity derivative contract assets and liabilities as of December 31, 2011, are summarized by year in the following table:
Source of Information-
Fair Value by Contract Year
 2012 2013 2014 2015 2016 Thereafter Total
  (In millions)
Prices actively quoted(1)
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Other external sources(2)
 (62) (7) (6) (5) —
 —
 (80)
Prices based on models —
 —
 —
 —
 8
 42
 50
Total(3)
 $(62) $(7) $(6) $(5) $8
 $42
 $(30)
(1)
Represents exchange traded New York Mercantile Exchange futures and options.
(2)
Primarily represents contracts based on broker and IntercontinentalExchange quotes.
(3)
Includes $(30) million in non-hedge commodity derivative contracts that are related to NUG contracts. NUG contracts are subject to regulatory accounting and do not materially impact earnings.
Met-Ed performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. Based on derivative contracts held as of December 31, 2011, an adverse 10% change in commodity prices would not have a material effect on Met-Ed’s net income for the next 12 months.
Interest Rate Risk
Met-Ed’s exposure to fluctuations in market interest rates is reduced since a significant portion of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for Met-Ed’s investment portfolio and debt obligations.
Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income           $234
 $234
 $234
Average interest rate           3.3% 3.3%  
Liabilities:                
Long-term Debt:                
Fixed rate   $150
 $250
     $300
 $700
 $796
Average interest rate   5.0% 4.9%     7.7% 6.1%  
Variable rate           $29
 $29
 $29
Average interest rate           0.1% 0.1%  
Equity Price Risk
NDT funds have been established to satisfy nuclear decommissioning obligations. Included in Met-Ed’s NDT are fixed income, equities and short-term investments carried at market values of approximately $234 million, $51 million and $23 million, respectively, as of December 31, 2011, excluding $2 million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $5 million reduction in fair value as of December 31, 2011. Met-Ed's NDT is 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. A decline


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in the value of Met-Ed's NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements.
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. Met-Ed evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. Met-Ed may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. Met-Ed monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.


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PENNSYLVANIA ELECTRIC COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec provides regulated electric transmission and distribution reliability deferralsservices in 2008,17,600 square miles of western, northern and south central Pennsylvania. The area it serves has a population of approximately 1.3 million. Penelec, as lessee of the property of its subsidiary, The Waverly Electric Light & Power Company, serves customers in the Waverly, New York vicinity. Penelec also procures generation service for those franchise customers who have elected to retain them as their power supplier. Penelec procures power under its DSP, in which full requirements products (energy, capacity, ancillary services and applicable transmission services) are procured through descending clock auctions.
For additional information with respect to Penelec, 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: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Contractual Obligations, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
On January 25, 2012, Penelec filed a Form 15 with the SEC to deregister its securities and suspend its obligation to file periodic reports under the Securities Exchange Act of 1934, as amended, except that the registrant has filed this Annual Report on Form 10-K for the year ended December 31, 2011. This Annual Report on Form 10-K will be the last filing made by Penelec with the SEC under the Exchange Act.
Results of Operations
Net income was unchanged in 2011, compared to 2010, due to lower purchased power costs, other operating expenses and income taxes, partially offset by lower MISO transmission cost deferralsrevenues and higher amortization of regulatory assets.
Revenues
Revenues decreased by $459 million, or 30%, in 2009.2011 compared to 2010. The decrease in general taxesrevenue was primarily due to lower Ohio KWH taxesdistribution, retail generation, wholesale generation and transmission revenues.
Distribution revenues decreased by $93 million in 20092011, compared to 2010, primarily due to lower rates resulting from the DSP, which eliminated the transmission component from the distribution rate beginning in 2011, partially offset by a PPUC-approved rate adjustment for NUG costs. Lower MWH deliveries to residential and commercial customers reflected decreased weather-related usage compared to 2010. Higher MWH deliveries to industrial customers were primarily due to recovering economic conditions in Penelec’s service territory, compared to 2010.
Changes in distribution MWH deliveries and revenues in 2011, compared to 2010, are summarized in the following tables:
Distribution MWH Deliveries
Increase
(Decrease)
Residential(2.2)%
Commercial(3.7)%
Industrial4.5 %
Net Decrease in Distribution Deliveries0.1 %
Distribution Revenues Decrease
  (In millions)
Residential $(35)
Commercial (31)
Industrial (27)
Decrease in Distribution Revenues $(93)

Retail generation revenues decreased by $218 million in 2011, compared to 2010, due to lower MWH sales in all customer classes resulting from increased customer shopping. The impact of customer shopping was partially offset by higher generation rates that reflect the inclusion of transmission services under the DSP, effective January 1, 2011, for all customer classes. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. In 2011, Penelec began deferring the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings.


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Changes in retail generation MWH sales and revenues in 2011, compared to 2010, are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(8.5)%
Commercial(53.6)%
Industrial(92.5)%
Decrease in Retail Generation Sales(53.1)%
Retail Generation Revenues 
Increase
(Decrease)
  (In millions)
Residential $87
Commercial (78)
Industrial (227)
Net Decrease in Retail Generation Revenues $(218)

Wholesale generation revenues decreased by $205 million in 2011, compared to 2010, reflecting lower RPM revenues for Penelec in the PJM market.
Transmission revenues decreased by $7 million in 2011, compared to 2010, primarily due to the termination of Penelec’s TSC rates effective January 1, 2011. Penelec deferred the difference between transmission revenues and transmission costs incurred, resulting in no material effect to earnings for the period.
Operating Expenses

Total operating expenses decreased by $446 million in 2011 as compared to 2008 and a $7.1 million adjustment recognized in 2009 related to2010. The following table presents changes from the prior periods.year by expense category:
Operating Expenses - Changes Increase (Decrease)
  (In millions)
Purchased power costs (467)
Other operating costs (99)
Pensions and OPEB mark-to-market adjustment 33
Provision for depreciation (3)
Amortization of regulatory assets, net 97
General taxes (7)
Net Decrease in Operating Expenses $(446)

Purchased power costs decreased by $467 million in 2011, compared to 2010, due to a decrease in MWH purchased to source generation sales requirements. Decreased power purchased from affiliates resulted from reduced requirements due to the increase in customer shopping described above and the termination of Penelec's partial requirements PSA with FES at the end of 2010. Other operating costs decreased by $99 million in 2011 due to lower transmission congestion and transmission loss expenses that are now included in the cost of purchased power (see reference to deferral accounting above). Increased pensions and OPEB mark-to-market adjustment charges were due to higher net actuarial losses in 2011 as compared to 2010. The amortization of regulatory assets increased by $97 million in 2011 primarily due to reduced NUG deferrals as a result of the PPUC-approved increase in Penelec’s NUG cost recovery rider in January 2011.
Other ExpensesExpense

Other expensesTotal other expense increased by $17$41 million in 20092011, compared to 20082010, primarily due to highera $57 million decrease in capitalized interest expense associated with the issuancecompletion of $300the Sammis AQC project in 2010, partially offset by lower interest expense ($5 million).
Market Risk Information
FES uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.
Commodity Price Risk
FES is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. FirstEnergy's Risk Policy 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 practice. FES uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.
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, FES relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FES uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making (see Note 9, Fair Value Measurements of the Combined Notes to the Consolidated Financial Statements). Sources of information for the valuation of commodity derivative contract assets and liabilities as of December 31, 2011, are summarized by year in the following table:
Source of Information-
Fair Value by Contract Year
 2012 2013 2014 2015 2016 Thereafter Total
  (In millions)
Prices actively quoted(1)
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Other external sources(2)
 (15) 11
 20
 8
 —
 —
 24
Prices based on models (6) —
 —
 —
 (2) (8) (16)
Total $(21) $11
 $20
 $8
 $(2) $(8) $8
(1)
Represents exchange traded New York Mercantile Exchange futures and options.
(2)
Primarily represents contracts based on broker and IntercontinentalExchange quotes.
FES performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. Based on derivative contracts held as of December 31, 2011, an adverse 10% change in commodity prices would decrease net income by approximately $7 million of FMBs by OE in October 2008.

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during the next 12 months.
Interest Rate Risk

OE’sFES’ exposure to fluctuations in market interest rates is reduced since a significant portion of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for OE’sFES’ investment portfolio and debt obligations.

Comparison of Carrying Value to Fair ValueComparison of Carrying Value to Fair Value             Comparison of Carrying Value to Fair Value
           There-   Fair 
Year of Maturity 2010 2011 2012 2013 2014 after Total Value  2012 2013 2014 2015 2016 There-after Total Fair Value
 (Dollars in millions)  (In millions)
Assets                 
Investments Other Than Cash                 
and Cash Equivalents:                 
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income
 $27  $29  $31  $37  $42  $106  $272  $301            $1,025
 $1,025
 $1,025
Average interest rate
  8.6%  8.7%  8.7%  8.7%  8.8%  6.7%  8.0%               6.5% 6.5%  
                                
Liabilities                                 
Liabilities:                
Long-term Debt:
                                                 
Fixed rate
 $1          $1      $1,167  $1,169  $1,299  $68
 $75
 $99
 $450
 $26
 $2,445
 $3,163
 $3,419
Average interest rate
  7.2%          5.4%      6.9%  6.9%     9.0% 9.0% 7.3% 5.1% 7.7% 5.1% 5.4%  
Short-term Borrowings:
 $94                      $94  $94 
Variable rate           $512
 $512
 $512
Average interest rate
  0.7%                      0.7%               0.1% 0.1%  


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Equity Price Risk
NDT funds have been established to satisfy NGC’s nuclear decommissioning obligations. Included in FES’s NDT are fixed income, equities and short-term investments carried at market values of approximately $1,025 million, $124 million and $132 million, respectively, as of December 31, 2011, excluding ($58) million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $12 million reduction in fair value as of December 31, 2011. NGC recognized in earnings the unrealized losses on available-for-sale securities held in their NDT as OTTI. A decline in the value of FES’s NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements.
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. FES evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. FES may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. FES monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.
Wholesale Credit Risk
FES measures wholesale credit risk as the replacement cost for derivatives in power, natural gas, coal and emission allowances, adjusted for amounts owed to or due from counterparties for settled transactions. The replacement cost of open positions represents unrealized gains, net of any unrealized losses, where FES has a legally enforceable right of setoff. FES monitors and manages the credit risk of wholesale marketing, risk management and energy transacting operation through credit policies and procedures, which include an established credit approval process, daily monitoring of counterparty credit limits, the use of credit mitigation measures such as margin, collateral and the use of master netting agreements. FES aggressively manages the quality of its portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB (S&P).
Retail Credit Risk
FES is exposed to retail credit risk through competitive electricity activities, which serve residential, commercial and industrial companies. Retail credit risk results when customers default on contractual obligations or fail to pay for service rendered. This risk represents the loss that may be incurred due to the nonpayment of customer accounts receivable balances, as well as the loss from the resale of energy previously committed to serve customers.
Retail credit risk is managed through established credit approval policies, monitoring customer exposures and the use of credit mitigation measures such as deposits in the form of letters of credit, cash or prepayment arrangements.
Retail credit quality is dependent on the economy and the ability of customers to manage through unfavorable economic cycles and other market changes. If the business environment were to be negatively affected by changes in economic or other market conditions, FES's retail credit risk may be adversely impacted.


107
113


THE CLEVELAND ELECTRIC ILLUMINATINGOHIO EDISON COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
OE is a wholly owned electric utility subsidiary of FirstEnergy. OE engages in the distribution and sale of electric energy to communities in a 7,000 square mile area of central and northeastern Ohio and, through its wholly owned subsidiary, Penn, 1,100 square miles in western Pennsylvania. OE and Penn conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services and procurement of generation services for those franchise customers electing to retain them as their power supplier. The areas served by OE and Penn have populations of approximately 2.3 million and 0.4 million, respectively.
For additional information with respect to OE, 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: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Contractual Obligations, Off-Balance Sheet Arrangements, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
Results of Operations
Net income decreased by $27 million in 2011 compared to 2010. The decrease primarily resulted from lower revenues and higher other operating expenses, partially offset by lower purchased power costs.
Revenues
Revenues decreased by $203 million, or 11%, in 2011 compared with 2010 due to lower retail generation revenues, partially offset by higher distribution and wholesale generation revenues.
Distribution revenues increased by $69 million in 2011, compared to 2010, due to increased MWH deliveries and higher average prices in all customer classes. The higher MWH deliveries in the residential class were driven primarily by increased load growth partially offset by lower weather-related usage. The increase in distribution deliveries to commercial and industrial customers was primarily due to recovering economic conditions in OE’s and Penn’s service territories. Higher average prices in all customer classes were principally due to the recovery of deferred distribution costs.
Changes in distribution MWH deliveries and revenues in 2011 compared to 2010, are summarized in the following tables:
Distribution MWH DeliveriesIncrease
Residential0.3%
Commercial0.7%
Industrial5.4%
Increase in Distribution Deliveries2.0%
Distribution Revenues Increase
  (In millions)
Residential $26
Commercial 17
Industrial 26
Increase in Distribution Revenues $69

Retail generation revenues decreased by $277 million primarily due to a decrease in MWH sales from increased customer shopping and lower average prices in all customer classes. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. OE and Penn defer the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings. Lower MWH sales were primarily the result of increased customer shopping in 2011. The increases in shopping by residential, commercial and industrial customers were 18%, 11% and 7%, respectively, in 2011 compared with 2010.


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Decreases in retail generation MWH sales and revenues in 2011 compared to 2010 are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(28.8)%
Commercial(34.0)%
Industrial(22.6)%
Decrease in Retail Generation Sales(28.3)%
Retail Generation Revenues Decrease
  (In millions)
Residential $(166)
Commercial (74)
Industrial (37)
Decrease in Retail Generation Revenues $(277)

Wholesale generation revenues increased by $12 million in 2011 compared to 2010 due to higher revenues from sales to NGC from OE’s leasehold interests in Perry Unit 1 and Beaver Valley Unit 2.
Operating Expenses
Total operating expenses decreased by $175 million in 2011 compared to 2010. The following table presents changes from the prior year by expense category:
Operating Expenses - Changes Increase (Decrease)
  (In millions)
Purchased power costs $(279)
Other operating expenses 109
Pensions and OPEB mark-to-market adjustment 19
Provision for depreciation 2
Amortization of regulatory assets, net (33)
General taxes 7
Net Decrease in Operating Expenses $(175)

Purchased power costs decreased in 2011 compared to 2010 due to lower MWH purchases resulting from reduced generation sales requirements coupled with lower unit costs. The increase in other operating expenses in 2011 compared to the same period of 2010 was principally due to expenses associated with nuclear refueling outages at OE’s leased Perry Unit 1 and Beaver Valley Unit 2 that were absent in 2010. Decreased pensions and OPEB mark-to-market adjustment charges are the result of lower net actuarial losses in 2011 compared to 2010. The amortization of regulatory assets decreased primarily due to higher deferred residential generation credits in 2011. General taxes increased as a result of higher property taxes.
Interest Rate Risk
OE’s exposure to fluctuations in market interest rates is reduced since all of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for OE’s investment portfolio and debt obligations.


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Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income $31
 $36
 $42
 $37
 $13
 $138
 $297
 $318
Average interest rate 8.7% 8.8% 8.8% 8.9% 8.9% 4.4% 6.8%  
Liabilities:                
Long-term Debt:                
Fixed rate       $150
 $250
 $757
 $1,157
 $1,434
Average interest rate       5.5% 6.4% 7.3% 6.9%  
Equity Price Risk
NDT funds have been established to satisfy nuclear decommissioning obligations. Included in OE’s NDT are fixed income and short-term investments carried at market values of approximately $134 million and $1 million, respectively, as of December 31, 2011, excluding $2 million of net receivables, payables and accrued income. OE recognizes in earnings the unrealized losses on available-for-sale securities held in its NDT as OTTI. A decline in the value of OE's NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During 2011, approximately $4 million was contributed to OE's NDT to comply with requirements under certain sale-leaseback transactions in which OE continues as a lessee.
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. OE evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. OE may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. OE monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.


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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, providingprovides regulated electric distribution services.services in an area of 1,600 square miles in northeastern Ohio. The area it serves has a population of approximately 1.7 million. CEI also providesprocures generation services tofor those customers electing to retain CEIthem 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 the Combined Notes to the Consolidated Financial Statements for a discussion of Ohio power supply procurement issues for 2009 and beyond.

For additional information with respect to CEI, please see the information contained in FirstEnergy's 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:subheadings: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Guarantees and Other Assurances, Strategy and Outlook,Contractual Obligations, Off-Balance Sheet Arrangements, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.

On January 25, 2012, CEI filed a Form 15 with the SEC to deregister its securities and suspend its obligation to file periodic reports under the Securities Exchange Act of 1934, as amended, except that the registrant has filed this Annual Report on Form 10-K for the year ended December 31, 2011. This Annual Report on Form 10-K will be the last filing made by CEI with the SEC under the Exchange Act.
Results of Operations

CEI experienced a loss applicable to parent of $13 million in 2009 compared to earningsEarnings available to parent of $285 million in 2008. The loss in 2009 resulted primarily from regulatory charges related to the implementation of CEI’s ESP, decreased revenues, and increased purchased power costs, partially offset by higher deferrals of regulatory assets and lower operating costs.

Revenues

Revenues decreased by $140$5 million or 7.7%, in 20092011 compared to 2008,2010. The decrease in earnings was primarily due primarily to decreases in distribution and transmissiondecreased revenues, partially offset by increaseslower purchased power costs and amortization of regulatory assets.
Revenues
Revenues decreased $345 million, or 28%, in 2011 compared to 2010 due to lower retail generation and distribution revenues.

Revenues from distribution throughputDistribution revenues decreased by $154$78 million in 2009,2011 compared to 20082010 due to a decrease in KWH deliveries and lower average unit prices forin all customer classes. The lower KWHclasses offset by increased MWH deliveries in 2009 were due primarily to weaker economic conditions, a decrease in cooling degree days of 14.5% and a decrease in heating degree days of 3.9%.the industrial sector. The lower average unit price wasprices were the result of lowerthe absence of transition ratescharges in 2009 (see Regulatory Matters – Ohio), partially offset by2011. Lower residential and commercial deliveries resulted from decreased weather-related usage in 2011. In the industrial sector, MWH deliveries increased primarily as a PUCO-approved distribution rate increase effective May 1, 2009.

result of recovering economic conditions in CEI's service territory.
Changes in distribution KWHMWH deliveries and revenues in 20092011 compared to 20082010 are summarized in the following tables.tables:

Distribution KWHMWH Deliveries DecreaseIncrease (Decrease)
   
Residential (3.20.3)%
Commercial (4.00.4)%
Industrial 1.4(14.7)%
DecreaseNet Increase in Distribution Deliveries 0.2(8.6)%


Distribution Revenues Decrease 
  (In millions) 
Residential $(56)
Commercial  (36)
Industrial  (62)
Decrease in Distribution Revenues $(154)

Transmission revenues decreased $21 million in 2009 as compared to 2008 due to the elimination of transmission revenues as part of the generation rate established under CEI’s CBP, effective June 1, 2009.

Distribution Revenues Decrease
  (In millions)
Residential $(12)
Commercial (7)
Industrial (59)
Decrease in Distribution Revenues $(78)
Retail generation revenues increased $48decreased $265 million in 20092011 as compared to 20082010 primarily due to higherlower MWH sales to all customer classes that resulted from increased customer shopping and lower average unit prices across all customer classes, partially offset by decreased sales volume to allfor the commercial and residential customer classes. AverageRetail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. CEI defers the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings. Lower MWH sales were the result of increased shopping by residential, commercial and industrial customers of 15%, 8% and 36%, respectively, in 2011 compared to 2010. Lower average unit prices increasedin the residential customer class were primarily due to an increasethe lower auction price in CEI’s fuel cost recovery rider that was effective from January through May 2009. In addition, effective June 1, 2009, the transmission tariff ended and the recovery of transmission costs is included in the generation rate established under CEI’s CBP. Reduced industrial KWH sales, principally to major automotive and steel customers, reflected weakened economic conditions.  Reduced sales due to increased customer shopping was experienced in all sectors in the fourth quarter of 2009.2011.


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114

Changes in retail generation sales and revenues in 20092011 compared to 20082010 are summarized in the following tables:

Retail KWHGeneration MWH Sales Decrease
   
Residential (14.138.8)%
Commercial (9.437.6)%
Industrial (20.5)%
Other(7.371.3)%
Decrease in Retail Generation Sales (15.852.2)%

Retail Generation Revenues Increase  Decrease
 (In millions)  (In millions)
Residential $14  $(88)
Commercial  17  (77)
Industrial  15  (100)
Other  2 
Increase in Generation Revenues $48 
Decrease in Retail Generation Revenues $(265)

Operating Expenses

Total operating expenses increased by $294decreased $336 million in 20092011 compared to 2008.2010. The following table presents the changechanges from the prior year by expense category:

Expenses  - Changes 
Increase
(Decrease)
 
  (In millions) 
Purchased power costs $210 
Other operating costs  (98)
Amortization of regulatory assets  207 
Deferral of new regulatory assets  (27)
General taxes  2 
Net Increase in Expenses $294 
Operating Expenses - Changes 
Increase
(Decrease)
  (In millions)
Purchased power costs $(254)
Other operating costs 15
Pensions and OPEB mark-to-market adjustment 8
Provision for depreciation 1
Amortization of regulatory assets, net (117)
General taxes 11
Net Decrease in Operating Expenses $(336)

Higher purchasedPurchased power costs reflect the results of CEI’s power procurement process for retail customersdecreased in 2009 (see Regulatory Matters – Ohio). Other operating costs decreased2011 primarily due to lower transmissionMWH purchases resulting from reduced sales requirements as a result of increased customer shopping. Other operating expenses (includedincreased due to 2011 inventory valuation adjustments. Increased pensions and OPEB mark-to-market adjustment changes were due to higher net actuarial losses in the cost of purchased power beginning June 1, 2009) and reduced labor and contractor costs, partially offset by costs associated with regulatory obligations for economic development and energy efficiency programs under CEI’s ESP, higher pension expense and restructuring costs. Increased amortization2011 as compared to 2010. Amortization of regulatory assets wasdecreased primarily due primarily to the impairmentcompletion of CEI’s Extended RTC regulatory asset of $216 million in accordance with the PUCO-approved ESP. Decreased costs from the increase in the deferral of new regulatory assets were due to CEI’s deferral of purchased power costs as approved by the PUCO, partially offset by lower deferrals of MISO transmission expenses and the absence of RCP distribution deferrals that ceasedtransition cost recovery at the end of 2008. The increase2010 and higher deferred purchased power costs in general2011, partially offset by increased recovery of deferred distribution costs and the absence in 2011 of renewable energy credit expenses that were deferred in 2010. General taxes was primarilyincreased due to higherincreased property taxes.

taxes as compared to 2010.
Interest Rate Risk

CEI has littleCEI's exposure to fluctuations in market interest rates because mostis reduced since all of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for CEI’s investment portfolio and debt obligations.


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Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income $66
 $75
 $80
 $50
 $16
   $287
 $315
Average interest rate 7.7% 7.7% 7.7% 7.7% 8.0%   7.7%  
Liabilities:                
Long-term Debt:                
Fixed rate   $325
 $26
 $24
 $6
 $1,450
 $1,831
 $2,162
Average interest rate   5.8% 7.7% 7.7% 7.7% 6.8% 6.7%  
Comparison of Carrying Value to Fair Value                   
                 There-     Fair 
Year of Maturity 2010  2011  2012  2013  2014  after  Total  Value 
  (Dollars in millions) 
Assets                        
Investments Other Than Cash                        
and Cash Equivalents:                        
Fixed Income
 $49  $53  $66  $75  $80  $66  $389  $432 
Average interest rate
  7.7%  7.7%  7.7%  7.7%  7.7%  7.8%  7.7%    
                                 
                                 
Liabilities
                                
Long-term Debt:
                                
Fixed rate
     $20  $22  $325  $26  $1,480  $1,873  $2,032 
Average interest rate
      7.7%  7.7%  5.8%  7.7%  6.8%  6.7%    
Short-term Borrowings:
 $340                      $340  $340 
Average interest rate
  1.1%                      1.1%    
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. CEI evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. CEI may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. CEI monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.


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115

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, providingprovides regulated electric distribution services.services in an area of 2,300 square miles in northwestern Ohio. The area it serves has a population of approximately 0.7 million. TE also provides generation services to those customers electing to retain TEthem 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 the 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 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: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Guarantees and Other Assurances, Strategy and Outlook,Contractual Obligations, Off-Balance Sheet Arrangements, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.

On January 25, 2012, TE filed a Form 15 with the SEC to deregister its securities and suspend its obligation to file periodic reports under the Securities Exchange Act of 1934, as amended, except that the registrant has filed this Annual Report on Form 10-K for the year ended December 31, 2011. This Annual Report on Form 10-K will be the last filing made by TE with the SEC under the Exchange Act.
Results of Operations

Earnings available to parent decreased by $2 millionin 2009 decreased2011 compared to $24 million from $75 million in 2008.2010. The decrease resultedwas primarily from lower electric sales revenues and higher other operating expenses, partially offset by lower purchased power costs from affiliates.
Revenues
Revenues decreased $40 million, or 8%, in 2011 compared to 2010, primarily due to lower retail generation sales, partially offset by a decreasean increase in the amortization of net regulatory assets and lower other operating costs.distribution revenues.

Revenues

Revenues decreased $62Distribution revenues increased $28 million or 6.9%, in 20092011 compared to 20082010, primarily due primarily to lower distributionhigher MWH deliveries to residential and wholesale generation revenues,industrial customers and higher unit prices to all customer classes related to increased energy efficiency rider rates, partially offset by lower MWH deliveries to commercial customers. Higher MWH deliveries to residential customers reflected increased retail generation revenues.

Revenues from distribution throughput decreased $173 million in 2009 compared to 2008 due to lower average unit prices and lower KWH sales in all customer classes that resulted primarily from adverse economic conditions. The effect of transition charges that ceased effective January 1, 2009, with the full recovery of related costs, was partiallyload growth slightly offset by lower weather-related usage that also drove lower deliveries to commercial customers. In the industrial sector, MWH deliveries increased primarily as a PUCO-approved distribution rate increase (see Regulatory Matters – Ohio).

result of recovering economic conditions in TE's service territory.
Changes in distribution KWHMWH deliveries and revenues in 2009 from 20082011 compared to 2010 are summarized in the following tables.tables:

Distribution KWHMWH Deliveries DecreaseIncrease (Decrease)
   
Residential 0.3 %
Commercial (4.71.9)%
Industrial2.4 %
Net Increase in Distribution Deliveries1.0 %
Distribution Revenues Increase
  (In millions)
Residential $11
Commercial 9
Industrial 8
Increase in Distribution Revenues $28
Retail generation revenues decreased $79 million in 2011 compared to 2010, primarily due to lower MWH sales from increased customer shopping and lower unit prices to all customer classes. The increases in shopping for residential, commercial and industrial customers were 13%, 9%, and 4%, respectively, in 2011 compared with 2010. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. TE defers the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings.


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Decreases in retail generation MWH sales and revenues in 2011 compared to 2010 are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(27.9)%
Commercial (9.439.7)%
Industrial (7.910.1)%
Decrease in Distribution DeliveriesRetail Generation Sales (7.620.5)%


Distribution Revenues Decrease 
Retail Generation Revenues Decrease
 (In millions)  (In millions)
Residential $(39) $(28)
Commercial  (79) (21)
Industrial  (55) (30)
Decrease in Distribution Revenues $(173)
Decrease in Retail Generation Revenues $(79)
Wholesale revenues decreased $6increased $12 million in 2009 as2011 compared to 20082010, primarily due to the expiration of a sales agreement with AMP-Ohio at the end of 2008, partially offset by higher revenues from associated sales to NGC from TE’s leasehold interest in Beaver Valley Unit 2.

Operating Expenses
116
Retail generation revenues increased $113Total operating expenses decreased $37 million in 20092011 compared to 2008 due to higher average prices across all customer classes and increased KWH sales to commercial customers, partially offset by a decrease in KWH sales to residential and industrial customers reflecting the impact of increased customer shopping in the fourth quarter of 2009. Average prices increased primarily due to an increase in TE's fuel cost recovery rider that was effective from January through May 2009. In addition, effective June 1, 2009, the transmission tariff ended and the recovery of transmission costs is included in the generation rate established under TE’s CBP. Reduced industrial KWH sales, principally to major automotive and steel customers, reflected weakened economic conditions. 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, resulting in an increase in sales volume for commercial customers.

Changes in retail electric generation KWH sales and revenues in 2009 from 2008 are summarized in the following tables.

Increase
Retail KWH Sales(Decrease)
Residential(10.0)%
Commercial10.2 %
Industrial(24.4)%
Net Decrease in Retail KWH Sales(13.2)%


Retail Generation Revenues Increase 
  
(In millions)
 
Residential $25 
Commercial  58 
Industrial  30 
Increase in Retail Generation Revenues $113 

Expenses

Total expenses increased $5 million in 2009 from 2008.2010. The following table presents changes from the prior year by expense category.category:

Expenses – Changes 
Increase
(Decrease)
 
  (In millions) 
Purchased power costs $
116
 
Other operating costs
  
(48
)
Provision for depreciation
  
(2
)
Amortization of regulatory assets, net
  
(56
)
General taxes
  
(5
)
Net Increase in Expenses
 
$
5
 
Operating Expenses - Changes Increase (Decrease)
  (In millions)
Purchased power costs $(76)
Other operating expenses 31
Pensions and OPEB mark-to-market adjustment 6
General taxes 2
Net Decrease in Operating Expenses $(37)

Higher purchasedPurchased power costs reflect the results of TE’s power procurement process for retail customersdecreased in 2009 (see Regulatory Matters – Ohio). Other2011 compared to 2010, due to lower MWH purchases resulting from reduced generation sales requirements in 2011 coupled with lower unit costs. The increase in other operating costs decreasedin 2011 was primarily due to reduced transmission expenses (includedassociated with the 2011 nuclear refueling outage at the leased Beaver Valley Unit 2 and an Ohio Supreme Court decision rendered in the costsecond quarter of power purchased from others beginning June 1, 2009), partially offset by costs associated with regulatory obligations for economic development2011 favoring a large industrial customer, both of which were absent in 2010. Increased pensions and energy efficiency programs under TE’s ESP. TheOPEB mark-to-market adjustment charges were due to higher net actuarial losses in 2011 as compared to 2010.
Other Expense
Other expense decreased slightly in 2011 compared to 2010, due to a decrease in net amortization of regulatory assets is primarily due to the completion of transition cost recovery,miscellaneous expense partially offset by lower MISO transmission cost deferralsinvestment income. The change in 2009.miscellaneous expense was due to decreased expenses associated with the accounts receivable securitization with Centerior Funding Corp., which was terminated in 2011 Investment income decreased principally due to lower NDT investment income.
Interest Rate Risk
TE's exposure to fluctuations in market interest rates is reduced since all of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for TE’s investment portfolio and debt obligations.


115


Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income   $25
 $26
 $24
 $6
 $53
 $134
 $145
Average interest rate   7.7% 7.7% 7.7% 7.7% 4.6% 6.4%  
Liabilities:                
Long-term Debt:                
Fixed rate           $600
 $600
 $741
Average interest rate           6.7% 6.7%  
Equity Price Risk
NDT funds have been established to satisfy nuclear decommissioning obligations. Included in TE’s NDT are fixed income, equities and short-term investments carried at market values of approximately $53 million, $27 million and $3 million, respectively, as of December 31, 2011. A hypothetical 10% decrease in general taxesprices quoted by stock exchanges would result in a $3 million reduction in fair value as of December 31, 2011. TE recognizes in earnings the unrealized losses on available-for-sale securities held in their NDT as OTTI. A decline in the value of TE’s NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During 2011, approximately $1 million was contributed to TE's NDT to comply with requirements under certain sale-leaseback transactions in which TE continues as a lessee.
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. TE evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. TE may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. TE monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.


116


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 in 3,200 square miles of northern, western and east central New Jersey. The area it serves has a population of approximately 2.7 million. JCP&L also has an ownership interest in a hydroelectric generating facility. In addition, JCP&L also procures generation services for franchise customers electing to retain them 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: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Contractual Obligations, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
Results of Operations
Net income decreased by $39 million in 2011 compared to 2010. The decrease was primarily due to lower Ohio KWH taxesrevenues, partially offset by reductions in 2009purchased power costs and amortization of regulatory assets.
Revenues
Revenues decreased by $532 million, or 18%, in 2011 compared to 2010. The decrease in revenues was due to lower distribution, retail generation and wholesale generation revenues, partially offset by an increase in other revenues.
Distribution revenues decreased by $187 million in 2011, compared to 2010, primarily due to an NJBPU-approved rate adjustment that became effective March 1, 2011 for all customer classes, and lower MWH deliveries. The lower MWH deliveries to residential customers were influenced by decreased weather-related usage in 2011. Lower distribution deliveries to commercial and industrial customers reflected the impact of economic conditions in JCP&L's service territory.
Decreases in distribution MWH deliveries and revenues in 2011 compared to 2010 are summarized in the following tables:
Distribution MWH DeliveriesDecrease
Residential(3.0)%
Commercial(2.9)%
Industrial(3.0)%
Decrease in Distribution Deliveries(2.9)%
Distribution Revenues Decrease
  (In millions)
Residential $(90)
Commercial (79)
Industrial (18)
Decrease in Distribution Revenues $(187)

Retail generation revenues decreased by $301 million due to lower generation MWH sales in all customer classes primarily due to an increase in customer shopping. The increases in shopping for residential, commercial and industrial customers were 10%, 9% and 5%, respectively, in 2011 compared with 2010. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. JCP&L defers the difference between retail generation revenues and purchased power costs, resulting in no material effect to earnings.


117


Decreases in retail generation MWH sales and revenues in 2011, compared to 2010, are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(13.0)%
Commercial(23.0)%
Industrial(29.0)%
Decrease in Retail Generation Sales(16.3)%
Retail Generation Revenues Decrease
  (In millions)
Residential $(181)
Commercial (108)
Industrial (12)
Decrease in Retail Generation Revenues $(301)

Wholesale generation revenues decreased by $54 million in 2011, compared to 2010, due to a decrease in PJM spot market energy sales.
Other revenues increased by $10 million in 2011, compared to 2010, primarily due to increases in PJM network transmission revenues and transition bond revenues from increased rates.
Operating Expenses
Total operating expenses decreased by $461 million in 2011 compared to 2010. The following table presents changes from the prior year by expense category:
Operating Expenses - Changes Increase (Decrease)
  (In millions)
Purchased power costs $(354)
Other operating expenses 48
Pensions and OPEB mark-to-market adjustment 34
Provision for depreciation 22
Amortization of regulatory assets, net (213)
General taxes 2
Net Decrease in Operating Expenses $(461)

Purchased power costs decreased by $354 million in 2011 due to lower requirements from reduced retail generation sales. Other operating expenses increased by $48 million in 2011 principally from storm restoration maintenance costs. Increased pensions and OPEB mark-to-market adjustment changes were due to higher net actuarial losses in 2011 as compared to 20082010. Amortization of regulatory assets, net, decreased by $213 million due to reduced cost recovery under the NJBPU-approved NUG tariffs that became effective March 1, 2011 and higher deferred storm restoration costs, partially offset by a charge for nonrecoverable NUG costs.
Market Risk Information
JCP&L uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.
Commodity Price Risk
JCP&L is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas and energy transmission. FirstEnergy's Risk Policy 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 practice. JCP&L uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.
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, JCP&L relies on model-based information. The model provides estimates of future


118


regional prices for electricity and an estimate of related price volatility. JCP&L uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making (see Note 9, Fair Value Measurements of the Combined Notes to the Consolidated Financial Statements). Sources of information for the valuation of commodity derivative contract assets and liabilities as of December 31, 2011, are summarized by year in the following table:
Source of Information-
Fair Value by Contract Year
 2012 2013 2014 2015 2016 Thereafter Total
  (In millions)
Prices actively quoted(1)
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Other external sources(2)
 (52) (43) (36) (14) —
 —
 (145)
Prices based on models —
 —
 —
 —
 1
 1
 2
Total(3)
 $(52) $(43) $(36) $(14) $1
 $1
 $(143)
(1)
Represents exchange traded New York Mercantile Exchange futures and options.
(2)
Primarily represents contracts based on broker and IntercontinentalExchange quotes.
(3)
Includes $(143) million in non-hedge commodity derivative contracts that are related to NUG contracts. NUG contracts are subject to regulatory accounting and do not materially impact earnings.
JCP&L performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. Based on derivative contracts held as of December 31, 2011, an adverse 10% change in commodity prices would not have a material effect on JCP&L’s net income for the next 12 months.
Interest Rate Risk
JCP&L’s exposure to fluctuations in market interest rates is reduced since all of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for JCP&L’s investment portfolio and debt obligations.
Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income           $363
 $363
 $363
Average interest rate           5.2% 5.2%  
Liabilities:                
Long-term Debt:                
Fixed rate $34
 $36
 $38
 $41
 $343
 $1,285
 $1,777
 $2,080
Average interest rate 5.7% 5.7% 5.9% 6.0% 5.7% 6.2% 6.1%  
Equity Price Risk
NDT funds have been established to satisfy nuclear decommissioning obligations. Included in JCP&L’s NDT are fixed income, equities and short-term investments carried at market values of approximately $147 million, $30 million and $14 million, respectively, as of December 31, 2011, excluding $2 million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $3 million reduction in fair value as of December 31, 2011. JCP&L's NDT is 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. A decline in the value of JCP&L's NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During 2011, approximately $1 million was contributed to JCP&L's NDT to comply with regulatory requirements.
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. JCP&L evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. JCP&L may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. JCP&L monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.


119


METROPOLITAN EDISON COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
Met-Ed is a wholly owned electric utility subsidiary of FirstEnergy. Met-Ed provides regulated electric transmission and distribution services in 3,300 square miles of eastern and south central Pennsylvania. The area it serves has a population of approximately 1.2 million. Met-Ed also procures generation service for those franchise customers who have elected to retain them as their power supplier. Met-Ed procures power under its DSP, in which full requirements products (energy, capacity, ancillary services, and applicable transmission services) are procured through descending clock auctions.
For additional information with respect to Met-Ed, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Contractual Obligations, Off-Balance Sheet Arrangements, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
On January 25, 2012, Met-Ed filed a Form 15 with the SEC to deregister its securities and suspend its obligation to file periodic reports under the Securities Exchange Act of 1934, as amended, except that the registrant has filed this Annual Report on Form 10-K for the year ended December 31, 2011. This Annual Report on Form 10-K will be the last filing made by Met-Ed with the SEC under the Exchange Act.
Results of Operations
Net income increased by $8 million in 2011 compared to 2010. The increase was primarily due to decreased purchased power costs, other operating expenses and amortization of net regulatory assets partially offset by decreased revenues.
Revenues
Revenue decreased $606 million, or 33%, in 2011 compared to 2010, reflecting lower KWHdistribution, retail generation, wholesale generation and transmission revenues.
Distribution revenues decreased $336 million in 2011 compared to 2010, primarily due to lower rates resulting from the DSP that began in 2011 that eliminated the transmission component from the distribution rates. The lower MWH deliveries to residential and commercial customers were influenced by decreased weather-related usage in 2011. In the industrial sector, MWH deliveries increased primarily as a result of recovering economic conditions in Met-Ed's service territory.
Changes in distribution MWH deliveries and revenues in 2011 compared to 2010 are summarized in the following tables:
Distribution MWH DeliveriesIncrease (Decrease)
Residential(1.4)%
Commercial(2.0)%
Industrial2.2 %
Net Decrease in Distribution Deliveries(0.2)%
Distribution Revenues Decrease
  (In millions)
Residential $(133)
Commercial (90)
Industrial (113)
Decrease in Distribution Revenues $(336)
In 2011, retail generation revenues decreased $52 million due to lower MWH sales to all customer classes resulting from increased customer shopping. The impact of increased customer shopping is partially offset by higher generation rates that reflect the inclusion of transmission services under the DSP, effective January 1, 2011, for all customer classes. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. In 2011, Met-Ed began deferring the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings.


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Changes in retail generation MWH sales and revenues in 2011 compared to 2010 are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(3.8)%
Commercial(49.1)%
Industrial(91.8)%
Net Decrease in Retail Generation Sales(45.7)%
Retail Generation Revenues Increase (Decrease)
  (In millions)
Residential $166
Commercial (24)
Industrial (194)
Net Decrease in Retail Generation Revenues $(52)
Wholesale revenues decreased $210 million in 2011 compared to 2010, primarily reflecting lower RPM revenues for Met-Ed in the PJM market.
Transmission revenues decreased $9 million in 2011 compared to 2010 primarily due to the termination of Met-Ed’s TSC rates effective January 1, 2011. Met-Ed deferred the difference between transmission revenues and transmission costs incurred, resulting in no material effect to earnings in the period.
Operating Expenses
Total operating expenses decreased $608 million in 2011 compared to 2010. The following table presents changes from the prior year by expense category:
Operating Expenses - Changes Increase (Decrease)
  (In millions)
Purchased power costs $(328)
Other operating costs (230)
Pensions and OPEB mark-to-market adjustment 26
Provision for depreciation 5
Amortization of regulatory assets, net (68)
General taxes (13)
Net Decrease in Operating Expenses $(608)
Purchased power costs decreased $328 million in 2011 compared to 2010 due to a $3.5decrease in MWH purchased to source generation sales requirements, partially offset by higher unit costs. Decreased power purchased from affiliates reflects the increase in customer shopping described above and the termination of Met-Ed's partial requirements PSA with FES at the end of 2010. Other operating costs decreased $230 million adjustment recognized in 2009 related2011 compared to prior periods,2010 due to lower transmission congestion and transmission loss expenses that are now included in the cost of purchased power (see reference to deferral accounting above), partially offset by increased costs for energy efficiency programs. Increased pensions and OPEB mark-to-market adjustment changes were due to higher net actuarial losses in 2011 as compared to 2010. The amortization of regulatory assets decreased $68 million in 2011 compared to 2010 primarily due to the termination of transmission and transition tariff riders at the end of 2010. General taxes decreased by $13 million in 2011 primarily due to lower gross receipts taxes.
Other Expense
Interest income decreased by $3 million in 2011 compared to 2010 primarily due to reduced CTC stranded asset balances.
Market Risk Information
Met-Ed uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.


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Commodity Price Risk
Met-Ed is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas and energy transmission. FirstEnergy's Risk Policy 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 practice. Met-Ed uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.
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, Met-Ed relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Met-Ed uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making (see Note 9, Fair Value Measurements of the Combined Notes to the Consolidated Financial Statements). Sources of information for the valuation of commodity derivative contract assets and liabilities as of December 31, 2011, are summarized by year in the following table:
Source of Information-
Fair Value by Contract Year
 2012 2013 2014 2015 2016 Thereafter Total
  (In millions)
Prices actively quoted(1)
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Other external sources(2)
 (62) (7) (6) (5) —
 —
 (80)
Prices based on models —
 —
 —
 —
 8
 42
 50
Total(3)
 $(62) $(7) $(6) $(5) $8
 $42
 $(30)
(1)
Represents exchange traded New York Mercantile Exchange futures and options.
(2)
Primarily represents contracts based on broker and IntercontinentalExchange quotes.
(3)
Includes $(30) million in non-hedge commodity derivative contracts that are related to NUG contracts. NUG contracts are subject to regulatory accounting and do not materially impact earnings.
Met-Ed performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. Based on derivative contracts held as of December 31, 2011, an adverse 10% change in commodity prices would not have a material effect on Met-Ed’s net income for the next 12 months.
Interest Rate Risk
Met-Ed’s exposure to fluctuations in market interest rates is reduced since a significant portion of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for Met-Ed’s investment portfolio and debt obligations.
Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income           $234
 $234
 $234
Average interest rate           3.3% 3.3%  
Liabilities:                
Long-term Debt:                
Fixed rate   $150
 $250
     $300
 $700
 $796
Average interest rate   5.0% 4.9%     7.7% 6.1%  
Variable rate           $29
 $29
 $29
Average interest rate           0.1% 0.1%  
Equity Price Risk
NDT funds have been established to satisfy nuclear decommissioning obligations. Included in Met-Ed’s NDT are fixed income, equities and short-term investments carried at market values of approximately $234 million, $51 million and $23 million, respectively, as of December 31, 2011, excluding $2 million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $5 million reduction in fair value as of December 31, 2011. Met-Ed's NDT is 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. A decline


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in the value of Met-Ed's NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements.
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. Met-Ed evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. Met-Ed may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. Met-Ed monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.


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PENNSYLVANIA ELECTRIC COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec provides regulated electric transmission and distribution services in 17,600 square miles of western, northern and south central Pennsylvania. The area it serves has a population of approximately 1.3 million. Penelec, as lessee of the property taxes.of its subsidiary, The Waverly Electric Light & Power Company, serves customers in the Waverly, New York vicinity. Penelec also procures generation service for those franchise customers who have elected to retain them as their power supplier. Penelec procures power under its DSP, in which full requirements products (energy, capacity, ancillary services and applicable transmission services) are procured through descending clock auctions.
For additional information with respect to Penelec, 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: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Contractual Obligations, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
On January 25, 2012, Penelec filed a Form 15 with the SEC to deregister its securities and suspend its obligation to file periodic reports under the Securities Exchange Act of 1934, as amended, except that the registrant has filed this Annual Report on Form 10-K for the year ended December 31, 2011. This Annual Report on Form 10-K will be the last filing made by Penelec with the SEC under the Exchange Act.
Results of Operations
Net income was unchanged in 2011, compared to 2010, due to lower purchased power costs, other operating expenses and income taxes, partially offset by lower revenues and higher amortization of regulatory assets.
Revenues
Revenues decreased by $459 million, or 30%, in 2011 compared to 2010. The decrease in revenue was primarily due to lower distribution, retail generation, wholesale generation and transmission revenues.
Distribution revenues decreased by $93 million in 2011, compared to 2010, primarily due to lower rates resulting from the DSP, which eliminated the transmission component from the distribution rate beginning in 2011, partially offset by a PPUC-approved rate adjustment for NUG costs. Lower MWH deliveries to residential and commercial customers reflected decreased weather-related usage compared to 2010. Higher MWH deliveries to industrial customers were primarily due to recovering economic conditions in Penelec’s service territory, compared to 2010.
Changes in distribution MWH deliveries and revenues in 2011, compared to 2010, are summarized in the following tables:
Distribution MWH Deliveries
Increase
(Decrease)
Residential(2.2)%
Commercial(3.7)%
Industrial4.5 %
Net Decrease in Distribution Deliveries0.1 %
Distribution Revenues Decrease
  (In millions)
Residential $(35)
Commercial (31)
Industrial (27)
Decrease in Distribution Revenues $(93)

Retail generation revenues decreased by $218 million in 2011, compared to 2010, due to lower MWH sales in all customer classes resulting from increased customer shopping. The impact of customer shopping was partially offset by higher generation rates that reflect the inclusion of transmission services under the DSP, effective January 1, 2011, for all customer classes. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. In 2011, Penelec began deferring the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings.


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Changes in retail generation MWH sales and revenues in 2011, compared to 2010, are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(8.5)%
Commercial(53.6)%
Industrial(92.5)%
Decrease in Retail Generation Sales(53.1)%
Retail Generation Revenues 
Increase
(Decrease)
  (In millions)
Residential $87
Commercial (78)
Industrial (227)
Net Decrease in Retail Generation Revenues $(218)

Wholesale generation revenues decreased by $205 million in 2011, compared to 2010, reflecting lower RPM revenues for Penelec in the PJM market.
Transmission revenues decreased by $7 million in 2011, compared to 2010, primarily due to the termination of Penelec’s TSC rates effective January 1, 2011. Penelec deferred the difference between transmission revenues and transmission costs incurred, resulting in no material effect to earnings for the period.
Operating Expenses

Total operating expenses decreased by $446 million in 2011 as compared to 2010. The following table presents changes from the prior year by expense category:
Operating Expenses - Changes Increase (Decrease)
  (In millions)
Purchased power costs (467)
Other operating costs (99)
Pensions and OPEB mark-to-market adjustment 33
Provision for depreciation (3)
Amortization of regulatory assets, net 97
General taxes (7)
Net Decrease in Operating Expenses $(446)

Purchased power costs decreased by $467 million in 2011, compared to 2010, due to a decrease in MWH purchased to source generation sales requirements. Decreased power purchased from affiliates resulted from reduced requirements due to the increase in customer shopping described above and the termination of Penelec's partial requirements PSA with FES at the end of 2010. Other operating costs decreased by $99 million in 2011 due to lower transmission congestion and transmission loss expenses that are now included in the cost of purchased power (see reference to deferral accounting above). Increased pensions and OPEB mark-to-market adjustment charges were due to higher net actuarial losses in 2011 as compared to 2010. The amortization of regulatory assets increased by $97 million in 2011 primarily due to reduced NUG deferrals as a result of the PPUC-approved increase in Penelec’s NUG cost recovery rider in January 2011.
Other Expense

OtherTotal other expense increased $6by $41 million in 20092011, compared to 2008,2010, primarily due to highera $57 million decrease in capitalized interest expense associated with the April 2009 issuancecompletion of $300 million senior secured notes,the Sammis AQC project in 2010, partially offset by increased nuclear decommissioning trust investment income.lower interest expense ($5 million).

Market Risk Information
FES uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.
Commodity Price Risk
FES is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. FirstEnergy's Risk Policy 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 practice. FES uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.
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, FES relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FES uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making (see Note 9, Fair Value Measurements of the Combined Notes to the Consolidated Financial Statements). Sources of information for the valuation of commodity derivative contract assets and liabilities as of December 31, 2011, are summarized by year in the following table:
Source of Information-
Fair Value by Contract Year
 2012 2013 2014 2015 2016 Thereafter Total
  (In millions)
Prices actively quoted(1)
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Other external sources(2)
 (15) 11
 20
 8
 —
 —
 24
Prices based on models (6) —
 —
 —
 (2) (8) (16)
Total $(21) $11
 $20
 $8
 $(2) $(8) $8
(1)
Represents exchange traded New York Mercantile Exchange futures and options.
(2)
Primarily represents contracts based on broker and IntercontinentalExchange quotes.
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FES performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. Based on derivative contracts held as of December 31, 2011, an adverse 10% change in commodity prices would decrease net income by approximately $7 million during the next 12 months.
Interest Rate Risk

TE has littleFES’ exposure to fluctuations in market interest rates because mostis reduced since a significant portion of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for FES’ investment portfolio and debt obligations.
Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income           $1,025
 $1,025
 $1,025
Average interest rate           6.5% 6.5%  
Liabilities:                
Long-term Debt:                
Fixed rate $68
 $75
 $99
 $450
 $26
 $2,445
 $3,163
 $3,419
Average interest rate 9.0% 9.0% 7.3% 5.1% 7.7% 5.1% 5.4%  
Variable rate           $512
 $512
 $512
Average interest rate           0.1% 0.1%  


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Equity Price Risk
NDT funds have been established to satisfy NGC’s nuclear decommissioning obligations. Included in FES’s NDT are fixed income, equities and short-term investments carried at market values of approximately $1,025 million, $124 million and $132 million, respectively, as of December 31, 2011, excluding ($58) million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $12 million reduction in fair value as of December 31, 2011. NGC recognized in earnings the unrealized losses on available-for-sale securities held in their NDT as OTTI. A decline in the value of FES’s NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements.
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. FES evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. FES may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. FES monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.
Wholesale Credit Risk
FES measures wholesale credit risk as the replacement cost for derivatives in power, natural gas, coal and emission allowances, adjusted for amounts owed to or due from counterparties for settled transactions. The replacement cost of open positions represents unrealized gains, net of any unrealized losses, where FES has a legally enforceable right of setoff. FES monitors and manages the credit risk of wholesale marketing, risk management and energy transacting operation through credit policies and procedures, which include an established credit approval process, daily monitoring of counterparty credit limits, the use of credit mitigation measures such as margin, collateral and the use of master netting agreements. FES aggressively manages the quality of its portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB (S&P).
Retail Credit Risk
FES is exposed to retail credit risk through competitive electricity activities, which serve residential, commercial and industrial companies. Retail credit risk results when customers default on contractual obligations or fail to pay for service rendered. This risk represents the loss that may be incurred due to the nonpayment of customer accounts receivable balances, as well as the loss from the resale of energy previously committed to serve customers.
Retail credit risk is managed through established credit approval policies, monitoring customer exposures and the use of credit mitigation measures such as deposits in the form of letters of credit, cash or prepayment arrangements.
Retail credit quality is dependent on the economy and the ability of customers to manage through unfavorable economic cycles and other market changes. If the business environment were to be negatively affected by changes in economic or other market conditions, FES's retail credit risk may be adversely impacted.


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OHIO EDISON COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
OE is a wholly owned electric utility subsidiary of FirstEnergy. OE engages in the distribution and sale of electric energy to communities in a 7,000 square mile area of central and northeastern Ohio and, through its wholly owned subsidiary, Penn, 1,100 square miles in western Pennsylvania. OE and Penn conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services and procurement of generation services for those franchise customers electing to retain them as their power supplier. The areas served by OE and Penn have populations of approximately 2.3 million and 0.4 million, respectively.
For additional information with respect to OE, 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: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Contractual Obligations, Off-Balance Sheet Arrangements, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
Results of Operations
Net income decreased by $27 million in 2011 compared to 2010. The decrease primarily resulted from lower revenues and higher other operating expenses, partially offset by lower purchased power costs.
Revenues
Revenues decreased by $203 million, or 11%, in 2011 compared with 2010 due to lower retail generation revenues, partially offset by higher distribution and wholesale generation revenues.
Distribution revenues increased by $69 million in 2011, compared to 2010, due to increased MWH deliveries and higher average prices in all customer classes. The higher MWH deliveries in the residential class were driven primarily by increased load growth partially offset by lower weather-related usage. The increase in distribution deliveries to commercial and industrial customers was primarily due to recovering economic conditions in OE’s and Penn’s service territories. Higher average prices in all customer classes were principally due to the recovery of deferred distribution costs.
Changes in distribution MWH deliveries and revenues in 2011 compared to 2010, are summarized in the following tables:
Distribution MWH DeliveriesIncrease
Residential0.3%
Commercial0.7%
Industrial5.4%
Increase in Distribution Deliveries2.0%
Distribution Revenues Increase
  (In millions)
Residential $26
Commercial 17
Industrial 26
Increase in Distribution Revenues $69

Retail generation revenues decreased by $277 million primarily due to a decrease in MWH sales from increased customer shopping and lower average prices in all customer classes. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. OE and Penn defer the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings. Lower MWH sales were primarily the result of increased customer shopping in 2011. The increases in shopping by residential, commercial and industrial customers were 18%, 11% and 7%, respectively, in 2011 compared with 2010.


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Decreases in retail generation MWH sales and revenues in 2011 compared to 2010 are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(28.8)%
Commercial(34.0)%
Industrial(22.6)%
Decrease in Retail Generation Sales(28.3)%
Retail Generation Revenues Decrease
  (In millions)
Residential $(166)
Commercial (74)
Industrial (37)
Decrease in Retail Generation Revenues $(277)

Wholesale generation revenues increased by $12 million in 2011 compared to 2010 due to higher revenues from sales to NGC from OE’s leasehold interests in Perry Unit 1 and Beaver Valley Unit 2.
Operating Expenses
Total operating expenses decreased by $175 million in 2011 compared to 2010. The following table presents changes from the prior year by expense category:
Operating Expenses - Changes Increase (Decrease)
  (In millions)
Purchased power costs $(279)
Other operating expenses 109
Pensions and OPEB mark-to-market adjustment 19
Provision for depreciation 2
Amortization of regulatory assets, net (33)
General taxes 7
Net Decrease in Operating Expenses $(175)

Purchased power costs decreased in 2011 compared to 2010 due to lower MWH purchases resulting from reduced generation sales requirements coupled with lower unit costs. The increase in other operating expenses in 2011 compared to the same period of 2010 was principally due to expenses associated with nuclear refueling outages at OE’s leased Perry Unit 1 and Beaver Valley Unit 2 that were absent in 2010. Decreased pensions and OPEB mark-to-market adjustment charges are the result of lower net actuarial losses in 2011 compared to 2010. The amortization of regulatory assets decreased primarily due to higher deferred residential generation credits in 2011. General taxes increased as a result of higher property taxes.
Interest Rate Risk
OE’s exposure to fluctuations in market interest rates is reduced since all of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for OE’s investment portfolio and debt obligations.


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Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income $31
 $36
 $42
 $37
 $13
 $138
 $297
 $318
Average interest rate 8.7% 8.8% 8.8% 8.9% 8.9% 4.4% 6.8%  
Liabilities:                
Long-term Debt:                
Fixed rate       $150
 $250
 $757
 $1,157
 $1,434
Average interest rate       5.5% 6.4% 7.3% 6.9%  
Equity Price Risk
NDT funds have been established to satisfy nuclear decommissioning obligations. Included in OE’s NDT are fixed income and short-term investments carried at market values of approximately $134 million and $1 million, respectively, as of December 31, 2011, excluding $2 million of net receivables, payables and accrued income. OE recognizes in earnings the unrealized losses on available-for-sale securities held in its NDT as OTTI. A decline in the value of OE's NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During 2011, approximately $4 million was contributed to OE's NDT to comply with requirements under certain sale-leaseback transactions in which OE continues as a lessee.
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. OE evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. OE may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. OE monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.


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THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI provides regulated electric distribution services in an area of 1,600 square miles in northeastern Ohio. The area it serves has a population of approximately 1.7 million. CEI also procures generation services for those customers electing to retain them 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: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Contractual Obligations, Off-Balance Sheet Arrangements, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
On January 25, 2012, CEI filed a Form 15 with the SEC to deregister its securities and suspend its obligation to file periodic reports under the Securities Exchange Act of 1934, as amended, except that the registrant has filed this Annual Report on Form 10-K for the year ended December 31, 2011. This Annual Report on Form 10-K will be the last filing made by CEI with the SEC under the Exchange Act.
Results of Operations
Earnings available to parent decreased by $5 million in 2011 compared to 2010. The decrease in earnings was primarily due to decreased revenues, partially offset by lower purchased power costs and amortization of regulatory assets.
Revenues
Revenues decreased $345 million, or 28%, in 2011 compared to 2010 due to lower retail generation and distribution revenues.
Distribution revenues decreased $78 million in 2011 compared to 2010 due to lower average unit prices in all customer classes offset by increased MWH deliveries to the industrial sector. The lower average unit prices were the result of the absence of transition charges in 2011. Lower residential and commercial deliveries resulted from decreased weather-related usage in 2011. In the industrial sector, MWH deliveries increased primarily as a result of recovering economic conditions in CEI's service territory.
Changes in distribution MWH deliveries and revenues in 2011 compared to 2010 are summarized in the following tables:
Distribution MWH DeliveriesIncrease (Decrease)
Residential(0.3)%
Commercial(0.4)%
Industrial1.4 %
Net Increase in Distribution Deliveries0.2 %
Distribution Revenues Decrease
  (In millions)
Residential $(12)
Commercial (7)
Industrial (59)
Decrease in Distribution Revenues $(78)
Retail generation revenues decreased $265 million in 2011 as compared to 2010 primarily due to lower MWH sales to all customer classes that resulted from increased customer shopping and lower average unit prices for the commercial and residential customer classes. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. CEI defers the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings. Lower MWH sales were the result of increased shopping by residential, commercial and industrial customers of 15%, 8% and 36%, respectively, in 2011 compared to 2010. Lower average unit prices in the residential customer class were primarily due to the lower auction price in 2011.


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Changes in retail generation sales and revenues in 2011 compared to 2010 are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(38.8)%
Commercial(37.6)%
Industrial(71.3)%
Decrease in Retail Generation Sales(52.2)%
Retail Generation Revenues Decrease
  (In millions)
Residential $(88)
Commercial (77)
Industrial (100)
Decrease in Retail Generation Revenues $(265)
Operating Expenses
Total operating expenses decreased $336 million in 2011 compared to 2010. The following table presents changes from the prior year by expense category:
Operating Expenses - Changes 
Increase
(Decrease)
  (In millions)
Purchased power costs $(254)
Other operating costs 15
Pensions and OPEB mark-to-market adjustment 8
Provision for depreciation 1
Amortization of regulatory assets, net (117)
General taxes 11
Net Decrease in Operating Expenses $(336)
Purchased power costs decreased in 2011 primarily due to lower MWH purchases resulting from reduced sales requirements as a result of increased customer shopping. Other operating expenses increased due to 2011 inventory valuation adjustments. Increased pensions and OPEB mark-to-market adjustment changes were due to higher net actuarial losses in 2011 as compared to 2010. Amortization of regulatory assets decreased primarily due to the completion of transition cost recovery at the end of 2010 and higher deferred purchased power costs in 2011, partially offset by increased recovery of deferred distribution costs and the absence in 2011 of renewable energy credit expenses that were deferred in 2010. General taxes increased due to increased property taxes as compared to 2010.
Interest Rate Risk
CEI's exposure to fluctuations in market interest rates is reduced since all of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for CEI’s investment portfolio and debt obligations.


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Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income $66
 $75
 $80
 $50
 $16
   $287
 $315
Average interest rate 7.7% 7.7% 7.7% 7.7% 8.0%   7.7%  
Liabilities:                
Long-term Debt:                
Fixed rate   $325
 $26
 $24
 $6
 $1,450
 $1,831
 $2,162
Average interest rate   5.8% 7.7% 7.7% 7.7% 6.8% 6.7%  
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. CEI evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. CEI may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. CEI monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.


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THE TOLEDO EDISON COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
TE is a wholly owned electric utility subsidiary of FirstEnergy. TE provides regulated electric distribution services in an area of 2,300 square miles in northwestern Ohio. The area it serves has a population of approximately 0.7 million. TE also provides generation services to those customers electing to retain them 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: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Contractual Obligations, Off-Balance Sheet Arrangements, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
On January 25, 2012, TE filed a Form 15 with the SEC to deregister its securities and suspend its obligation to file periodic reports under the Securities Exchange Act of 1934, as amended, except that the registrant has filed this Annual Report on Form 10-K for the year ended December 31, 2011. This Annual Report on Form 10-K will be the last filing made by TE with the SEC under the Exchange Act.
Results of Operations
Earnings available to parent decreased by $2 million in 2011 compared to 2010. The decrease was primarily from lower revenues and higher other operating expenses, partially offset by lower purchased power costs from affiliates.
Revenues
Revenues decreased $40 million, or 8%, in 2011 compared to 2010, primarily due to lower retail generation sales, partially offset by an increase in distribution revenues.
Distribution revenues increased $28 million in 2011 compared to 2010, primarily due to higher MWH deliveries to residential and industrial customers and higher unit prices to all customer classes related to increased energy efficiency rider rates, partially offset by lower MWH deliveries to commercial customers. Higher MWH deliveries to residential customers reflected increased load growth slightly offset by lower weather-related usage that also drove lower deliveries to commercial customers. In the industrial sector, MWH deliveries increased primarily as a result of recovering economic conditions in TE's service territory.
Changes in distribution MWH deliveries and revenues in 2011 compared to 2010 are summarized in the following tables:
Distribution MWH DeliveriesIncrease (Decrease)
Residential0.3 %
Commercial(1.9)%
Industrial2.4 %
Net Increase in Distribution Deliveries1.0 %
Distribution Revenues Increase
  (In millions)
Residential $11
Commercial 9
Industrial 8
Increase in Distribution Revenues $28
Retail generation revenues decreased $79 million in 2011 compared to 2010, primarily due to lower MWH sales from increased customer shopping and lower unit prices to all customer classes. The increases in shopping for residential, commercial and industrial customers were 13%, 9%, and 4%, respectively, in 2011 compared with 2010. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. TE defers the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings.


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Decreases in retail generation MWH sales and revenues in 2011 compared to 2010 are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(27.9)%
Commercial(39.7)%
Industrial(10.1)%
Decrease in Retail Generation Sales(20.5)%
Retail Generation Revenues Decrease
  (In millions)
Residential $(28)
Commercial (21)
Industrial (30)
Decrease in Retail Generation Revenues $(79)
Wholesale revenues increased $12 million in 2011 compared to 2010, primarily due to higher revenues from sales to NGC from TE’s leasehold interest in Beaver Valley Unit 2.
Operating Expenses
Total operating expenses decreased $37 million in 2011 compared to 2010. The following table presents changes from the prior year by expense category:
Operating Expenses - Changes Increase (Decrease)
  (In millions)
Purchased power costs $(76)
Other operating expenses 31
Pensions and OPEB mark-to-market adjustment 6
General taxes 2
Net Decrease in Operating Expenses $(37)
Purchased power costs decreased in 2011 compared to 2010, due to lower MWH purchases resulting from reduced generation sales requirements in 2011 coupled with lower unit costs. The increase in other operating costs in 2011 was primarily due to expenses associated with the 2011 nuclear refueling outage at the leased Beaver Valley Unit 2 and an Ohio Supreme Court decision rendered in the second quarter of 2011 favoring a large industrial customer, both of which were absent in 2010. Increased pensions and OPEB mark-to-market adjustment charges were due to higher net actuarial losses in 2011 as compared to 2010.
Other Expense
Other expense decreased slightly in 2011 compared to 2010, due to a decrease in miscellaneous expense partially offset by lower investment income. The change in miscellaneous expense was due to decreased expenses associated with the accounts receivable securitization with Centerior Funding Corp., which was terminated in 2011 Investment income decreased principally due to lower NDT investment income.
Interest Rate Risk
TE's exposure to fluctuations in market interest rates is reduced since all of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for TE’s investment portfolio and debt obligations.


Comparison of Carrying Value to Fair Value 
            There-   Fair 
Year of Maturity 2010 2011 2012 2013 2014 after Total Value 
  (Dollars in millions) 
Assets                 
Investments Other Than Cash
and Cash Equivalents:
                 
Fixed Income
  $18  $20  $22  $25  $26  $102  $213  $231 
Average interest rate
   7.7%  7.7%  7.7%  7.7%  7.7%  5.4%  6.6%    
                                  
Liabilities
                                 
Long-term Debt:
                                 
Fixed rate
                      $600  $600  $638 
Average interest rate
                       6.7%  6.7%    
Short-term Borrowings:
  $226                      $226  $226 
Average interest rate
   0.7%                      0.7%    
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Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income   $25
 $26
 $24
 $6
 $53
 $134
 $145
Average interest rate   7.7% 7.7% 7.7% 7.7% 4.6% 6.4%  
Liabilities:                
Long-term Debt:                
Fixed rate           $600
 $600
 $741
Average interest rate           6.7% 6.7%  
Equity Price Risk
NDT funds have been established to satisfy nuclear decommissioning obligations. Included in TE’s NDT are fixed income, equities and short-term investments carried at market values of approximately $53 million, $27 million and $3 million, respectively, as of December 31, 2011. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $3 million reduction in fair value as of December 31, 2011. TE recognizes in earnings the unrealized losses on available-for-sale securities held in their NDT as OTTI. A decline in the value of TE’s NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During 2011, approximately $1 million was contributed to TE's NDT to comply with requirements under certain sale-leaseback transactions in which TE continues as a lessee.
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. TE evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. TE may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. TE monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.


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118
JERSEYJERSEY 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.services in 3,200 square miles of northern, western and east central New Jersey. The area it serves has a population of approximately 2.7 million. JCP&L also provideshas an ownership interest in a hydroelectric generating facility. In addition, JCP&L also procures generation services tofor franchise customers electing to retain JCP&Lthem 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 ManagementManagement’s Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Guarantees and Other Assurances, Strategy and Outlook,Contractual Obligations, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.

Results of Operations

Net income decreaseddecreased by $39 million in 2011 compared to $170 million from $187 million in 2009.2010. The decrease was primarily due to lower revenues, partially offset by lowerreductions in purchased power costs and reduced amortization of regulatory assets.

Revenues

Revenues decreaseddecreased by $480$532 million, or 14%18%, in 2009,2011 compared with 2008.to 2010. The decrease in revenues is primarilywas due to a decrease inlower distribution, retail generation and wholesale generation revenues, retail generation revenues, and distribution revenues.

Wholesale generation revenues decreased $232 million in 2009 compared to 2008 due to lower market prices ($174 million) and a decrease in sales volume ($58 million) primarily resulting from the termination of a NUG contract in October 2008.

Retail generation revenues decreased $193 million in 2009 compared to 2008 due to lower retail generation KWH sales in all sectors, partially offset by higher unit pricesan increase in the residential and commercial sectors. Lower salesother revenues.
Distribution revenues decreased by $187 million in 2011, compared to the residential sector reflected milder weather in JCP&L’s service territory, while the decrease in sales to the commercial sector was2010, primarily due to an increaseNJBPU-approved rate adjustment that became effective March 1, 2011 for all customer classes, and lower MWH deliveries. The lower MWH deliveries to residential customers were influenced by decreased weather-related usage in 2011. Lower distribution deliveries to commercial and industrial customers reflected the numberimpact of shopping customers. Industrial sales were lower as a result of weakened economic conditions.conditions in JCP&L's service territory.

ChangesDecreases in retail generation KWH salesdistribution MWH deliveries and revenues by customer class in 20092011 compared to 20082010 are summarized in the following tables:

Retail Generation KWH Sales
Distribution MWH Deliveries Decrease
   
Residential (4.73.0)%
Commercial (23.92.9)%
Industrial (16.0)%
Decrease in Generation Sales(13.0)%


Retail Generation Revenues Decrease 
  (In millions) 
Residential $(11)
Commercial  (165)
Industrial  (17)
Decrease in Generation Revenues $(193)

Distribution revenues decreased $51 million in 2009 compared to 2008 due to lower KWH deliveries, reflecting milder weather and weakened economic conditions in JCP&L’s service territory, partially offset by an increase in composite unit prices.

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Changes in distribution KWH deliveries and revenues by customer class in 2009 compared to 2008 are summarized in the following tables:

Distribution KWH DeliveriesDecrease
Residential(4.7)%
Commercial(4.0)%
Industrial(11.83.0)%
Decrease in Distribution Deliveries (5.22.9)%

Distribution Revenues Decrease
  (In millions)
Residential $(90)
Commercial (79)
Industrial (18)
Decrease in Distribution Revenues $(187)

Distribution Revenues Decrease 
  (In millions) 
Residential $(28)
Commercial  (18)
Industrial  (5)
Decrease in Distribution Revenues $(51)
Retail generation revenues decreased by $301 million due to lower generation MWH sales in all customer classes primarily due to an increase in customer shopping. The increases in shopping for residential, commercial and industrial customers were 10%, 9% and 5%, respectively, in 2011 compared with 2010. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. JCP&L defers the difference between retail generation revenues and purchased power costs, resulting in no material effect to earnings.


117


Decreases in retail generation MWH sales and revenues in 2011, compared to 2010, are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(13.0)%
Commercial(23.0)%
Industrial(29.0)%
Decrease in Retail Generation Sales(16.3)%
Retail Generation Revenues Decrease
  (In millions)
Residential $(181)
Commercial (108)
Industrial (12)
Decrease in Retail Generation Revenues $(301)

Wholesale generation revenues decreased by $54 million in 2011, compared to 2010, due to a decrease in PJM spot market energy sales.
Other revenues increased by $10 million in 2011, compared to 2010, primarily due to increases in PJM network transmission revenues and transition bond revenues from increased rates.
Operating Expenses

Total operating expenses decreased by $435$461 million in 20092011 compared to 2008.2010. The following table presents changes from the prior year by expense category:
Operating Expenses - Changes Increase (Decrease)
  (In millions)
Purchased power costs $(354)
Other operating expenses 48
Pensions and OPEB mark-to-market adjustment 34
Provision for depreciation 22
Amortization of regulatory assets, net (213)
General taxes 2
Net Decrease in Operating Expenses $(461)

Expenses - Changes 
Increase
(Decrease)
 
  (In millions) 
Purchased power costs $(424)
Other operating costs  8 
Provision for depreciation  6 
Amortization of regulatory assets  (21)
General taxes  (4)
Net decrease in expenses $(435)

Purchased power costs decreased by $354 millionin 20092011 due to lower requirements from reduced retail generation sales. Other operating expenses increased by $48 million in 2011 principally from storm restoration maintenance costs. Increased pensions and OPEB mark-to-market adjustment changes were due to higher net actuarial losses in 2011 as compared to 2010. Amortization of regulatory assets, net, decreased by $213 million due to reduced cost recovery under the NJBPU-approved NUG tariffs that became effective March 1, 2011 and higher deferred storm restoration costs, partially offset by a charge for nonrecoverable NUG costs.
Market Risk Information
JCP&L uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.
Commodity Price Risk
JCP&L is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas and energy transmission. FirstEnergy's Risk Policy 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 practice. JCP&L uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.
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, JCP&L relies on model-based information. The model provides estimates of future


118


regional prices for electricity and an estimate of related price volatility. JCP&L uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making (see Note 9, Fair Value Measurements of the Combined Notes to the Consolidated Financial Statements). Sources of information for the valuation of commodity derivative contract assets and liabilities as of December 31, 2011, are summarized by year in the following table:
Source of Information-
Fair Value by Contract Year
 2012 2013 2014 2015 2016 Thereafter Total
  (In millions)
Prices actively quoted(1)
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Other external sources(2)
 (52) (43) (36) (14) —
 —
 (145)
Prices based on models —
 —
 —
 —
 1
 1
 2
Total(3)
 $(52) $(43) $(36) $(14) $1
 $1
 $(143)
(1)
Represents exchange traded New York Mercantile Exchange futures and options.
(2)
Primarily represents contracts based on broker and IntercontinentalExchange quotes.
(3)
Includes $(143) million in non-hedge commodity derivative contracts that are related to NUG contracts. NUG contracts are subject to regulatory accounting and do not materially impact earnings.
JCP&L performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. Based on derivative contracts held as of December 31, 2011, an adverse 10% change in commodity prices would not have a material effect on JCP&L’s net income for the next 12 months.
Interest Rate Risk
JCP&L’s exposure to fluctuations in market interest rates is reduced since all of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for JCP&L’s investment portfolio and debt obligations.
Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income           $363
 $363
 $363
Average interest rate           5.2% 5.2%  
Liabilities:                
Long-term Debt:                
Fixed rate $34
 $36
 $38
 $41
 $343
 $1,285
 $1,777
 $2,080
Average interest rate 5.7% 5.7% 5.9% 6.0% 5.7% 6.2% 6.1%  
Equity Price Risk
NDT funds have been established to satisfy nuclear decommissioning obligations. Included in JCP&L’s NDT are fixed income, equities and short-term investments carried at market values of approximately $147 million, $30 million and $14 million, respectively, as of December 31, 2011, excluding $2 million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $3 million reduction in fair value as of December 31, 2011. JCP&L's NDT is 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. A decline in the value of JCP&L's NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During 2011, approximately $1 million was contributed to JCP&L's NDT to comply with regulatory requirements.
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. JCP&L evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. JCP&L may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. JCP&L monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.


119


METROPOLITAN EDISON COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
Met-Ed is a wholly owned electric utility subsidiary of FirstEnergy. Met-Ed provides regulated electric transmission and distribution services in 3,300 square miles of eastern and south central Pennsylvania. The area it serves has a population of approximately 1.2 million. Met-Ed also procures generation service for those franchise customers who have elected to retain them as their power supplier. Met-Ed procures power under its DSP, in which full requirements products (energy, capacity, ancillary services, and applicable transmission services) are procured through descending clock auctions.
For additional information with respect to Met-Ed, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Contractual Obligations, Off-Balance Sheet Arrangements, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
On January 25, 2012, Met-Ed filed a Form 15 with the SEC to deregister its securities and suspend its obligation to file periodic reports under the Securities Exchange Act of 1934, as amended, except that the registrant has filed this Annual Report on Form 10-K for the year ended December 31, 2011. This Annual Report on Form 10-K will be the last filing made by Met-Ed with the SEC under the Exchange Act.
Results of Operations
Net income increased by $8 million in 2011 compared to 2010. The increase was primarily due to decreased purchased power costs, other operating expenses and amortization of net regulatory assets partially offset by decreased revenues.
Revenues
Revenue decreased $606 million, or 33%, in 2011 compared to 2010, reflecting lower distribution, retail generation, wholesale generation and transmission revenues.
Distribution revenues decreased $336 million in 2011 compared to 2010, primarily due to lower rates resulting from the DSP that began in 2011 that eliminated the transmission component from the distribution rates. The lower MWH deliveries to residential and commercial customers were influenced by decreased weather-related usage in 2011. In the industrial sector, MWH deliveries increased primarily as a result of recovering economic conditions in Met-Ed's service territory.
Changes in distribution MWH deliveries and revenues in 2011 compared to 2010 are summarized in the following tables:
Distribution MWH DeliveriesIncrease (Decrease)
Residential(1.4)%
Commercial(2.0)%
Industrial2.2 %
Net Decrease in Distribution Deliveries(0.2)%
Distribution Revenues Decrease
  (In millions)
Residential $(133)
Commercial (90)
Industrial (113)
Decrease in Distribution Revenues $(336)
In 2011, retail generation revenues decreased $52 million due to lower MWH sales to all customer classes resulting from increased customer shopping. The impact of increased customer shopping is partially offset by higher generation rates that reflect the inclusion of transmission services under the DSP, effective January 1, 2011, for all customer classes. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. In 2011, Met-Ed began deferring the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings.


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Changes in retail generation MWH sales and revenues in 2011 compared to 2010 are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(3.8)%
Commercial(49.1)%
Industrial(91.8)%
Net Decrease in Retail Generation Sales(45.7)%
Retail Generation Revenues Increase (Decrease)
  (In millions)
Residential $166
Commercial (24)
Industrial (194)
Net Decrease in Retail Generation Revenues $(52)
Wholesale revenues decreased $210 million in 2011 compared to 2010, primarily reflecting lower RPM revenues for Met-Ed in the PJM market.
Transmission revenues decreased $9 million in 2011 compared to 2010 primarily due to the lower KWHtermination of Met-Ed’s TSC rates effective January 1, 2011. Met-Ed deferred the difference between transmission revenues and transmission costs incurred, resulting in no material effect to earnings in the period.
Operating Expenses
Total operating expenses decreased $608 million in 2011 compared to 2010. The following table presents changes from the prior year by expense category:
Operating Expenses - Changes Increase (Decrease)
  (In millions)
Purchased power costs $(328)
Other operating costs (230)
Pensions and OPEB mark-to-market adjustment 26
Provision for depreciation 5
Amortization of regulatory assets, net (68)
General taxes (13)
Net Decrease in Operating Expenses $(608)
Purchased power costs decreased $328 million in 2011 compared to 2010 due to a decrease in MWH purchased to source generation sales requirements, discussed above, partially offset by higher retail unit prices.costs. Decreased power purchased from affiliates reflects the increase in customer shopping described above and the termination of Met-Ed's partial requirements PSA with FES at the end of 2010. Other operating costs decreased $230 million in 2011 compared to 2010 due to lower transmission congestion and transmission loss expenses that are now included in the cost of purchased power (see reference to deferral accounting above), partially offset by increased in 2009 primarilycosts for energy efficiency programs. Increased pensions and OPEB mark-to-market adjustment changes were due to higher expenses relatednet actuarial losses in 2011 as compared to employee benefits. Depreciation expense increased due to an increase in depreciable property since 2008. Amortization2010. The amortization of regulatory assets decreased $68 millionin 20092011 compared to 2010 primarily due to the full recoverytermination of certain regulatory assets in June 2008.transmission and transition tariff riders at the end of 2010. General taxes decreased principallyby $13 million in 2011 primarily due to lower gross receipts taxes.
Other Expense
Interest income decreased by $3 million in 2011 compared to 2010 primarily due to reduced CTC stranded asset balances.
Market Risk Information
Met-Ed uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.


121


Commodity Price Risk
Met-Ed is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas and energy transmission. FirstEnergy's Risk Policy 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 practice. Met-Ed uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.
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, Met-Ed relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Met-Ed uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making (see Note 9, Fair Value Measurements of the Combined Notes to the Consolidated Financial Statements). Sources of information for the valuation of commodity derivative contract assets and liabilities as of December 31, 2011, are summarized by year in the following table:
Source of Information-
Fair Value by Contract Year
 2012 2013 2014 2015 2016 Thereafter Total
  (In millions)
Prices actively quoted(1)
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Other external sources(2)
 (62) (7) (6) (5) —
 —
 (80)
Prices based on models —
 —
 —
 —
 8
 42
 50
Total(3)
 $(62) $(7) $(6) $(5) $8
 $42
 $(30)
(1)
Represents exchange traded New York Mercantile Exchange futures and options.
(2)
Primarily represents contracts based on broker and IntercontinentalExchange quotes.
(3)
Includes $(30) million in non-hedge commodity derivative contracts that are related to NUG contracts. NUG contracts are subject to regulatory accounting and do not materially impact earnings.
Met-Ed performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. Based on derivative contracts held as of December 31, 2011, an adverse 10% change in commodity prices would not have a material effect on Met-Ed’s net income for the next 12 months.
Interest Rate Risk
Met-Ed’s exposure to fluctuations in market interest rates is reduced since a significant portion of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for Met-Ed’s investment portfolio and debt obligations.
Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income           $234
 $234
 $234
Average interest rate           3.3% 3.3%  
Liabilities:                
Long-term Debt:                
Fixed rate   $150
 $250
     $300
 $700
 $796
Average interest rate   5.0% 4.9%     7.7% 6.1%  
Variable rate           $29
 $29
 $29
Average interest rate           0.1% 0.1%  
Equity Price Risk
NDT funds have been established to satisfy nuclear decommissioning obligations. Included in Met-Ed’s NDT are fixed income, equities and short-term investments carried at market values of approximately $234 million, $51 million and $23 million, respectively, as of December 31, 2011, excluding $2 million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $5 million reduction in fair value as of December 31, 2011. Met-Ed's NDT is 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. A decline


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in the value of Met-Ed's NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements.
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. Met-Ed evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. Met-Ed may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. Met-Ed monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.


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PENNSYLVANIA ELECTRIC COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec provides regulated electric transmission and distribution services in 17,600 square miles of western, northern and south central Pennsylvania. The area it serves has a population of approximately 1.3 million. Penelec, as lessee of the property of its subsidiary, The Waverly Electric Light & Power Company, serves customers in the Waverly, New York vicinity. Penelec also procures generation service for those franchise customers who have elected to retain them as their power supplier. Penelec procures power under its DSP, in which full requirements products (energy, capacity, ancillary services and applicable transmission services) are procured through descending clock auctions.
For additional information with respect to Penelec, 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: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Contractual Obligations, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
On January 25, 2012, Penelec filed a Form 15 with the SEC to deregister its securities and suspend its obligation to file periodic reports under the Securities Exchange Act of 1934, as amended, except that the registrant has filed this Annual Report on Form 10-K for the year ended December 31, 2011. This Annual Report on Form 10-K will be the last filing made by Penelec with the SEC under the Exchange Act.
Results of Operations
Net income was unchanged in 2011, compared to 2010, due to lower purchased power costs, other operating expenses and income taxes, partially offset by lower revenues and higher amortization of regulatory assets.
Revenues
Revenues decreased by $459 million, or 30%, in 2011 compared to 2010. The decrease in revenue was primarily due to lower distribution, retail generation, wholesale generation and transmission revenues.
Distribution revenues decreased by $93 million in 2011, compared to 2010, primarily due to lower rates resulting from the DSP, which eliminated the transmission component from the distribution rate beginning in 2011, partially offset by a PPUC-approved rate adjustment for NUG costs. Lower MWH deliveries to residential and commercial customers reflected decreased weather-related usage compared to 2010. Higher MWH deliveries to industrial customers were primarily due to recovering economic conditions in Penelec’s service territory, compared to 2010.
Changes in distribution MWH deliveries and revenues in 2011, compared to 2010, are summarized in the following tables:
Distribution MWH Deliveries
Increase
(Decrease)
Residential(2.2)%
Commercial(3.7)%
Industrial4.5 %
Net Decrease in Distribution Deliveries0.1 %
Distribution Revenues Decrease
  (In millions)
Residential $(35)
Commercial (31)
Industrial (27)
Decrease in Distribution Revenues $(93)

Retail generation revenues decreased by $218 million in 2011, compared to 2010, due to lower MWH sales in all customer classes resulting from increased customer shopping. The impact of customer shopping was partially offset by higher generation rates that reflect the inclusion of transmission services under the DSP, effective January 1, 2011, for all customer classes. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. In 2011, Penelec began deferring the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings.


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Changes in retail generation MWH sales and revenues in 2011, compared to 2010, are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(8.5)%
Commercial(53.6)%
Industrial(92.5)%
Decrease in Retail Generation Sales(53.1)%
Retail Generation Revenues 
Increase
(Decrease)
  (In millions)
Residential $87
Commercial (78)
Industrial (227)
Net Decrease in Retail Generation Revenues $(218)

Wholesale generation revenues decreased by $205 million in 2011, compared to 2010, reflecting lower RPM revenues for Penelec in the PJM market.
Transmission revenues decreased by $7 million in 2011, compared to 2010, primarily due to the termination of Penelec’s TSC rates effective January 1, 2011. Penelec deferred the difference between transmission revenues and transmission costs incurred, resulting in no material effect to earnings for the period.
Operating Expenses

Total operating expenses decreased by $446 million in 2011 as compared to 2010. The following table presents changes from the prior year by expense category:
Operating Expenses - Changes Increase (Decrease)
  (In millions)
Purchased power costs (467)
Other operating costs (99)
Pensions and OPEB mark-to-market adjustment 33
Provision for depreciation (3)
Amortization of regulatory assets, net 97
General taxes (7)
Net Decrease in Operating Expenses $(446)

Purchased power costs decreased by $467 million in 2011, compared to 2010, due to a decrease in MWH purchased to source generation sales requirements. Decreased power purchased from affiliates resulted from reduced requirements due to the increase in customer shopping described above and the termination of Penelec's partial requirements PSA with FES at the end of 2010. Other operating costs decreased by $99 million in 2011 due to lower transmission congestion and transmission loss expenses that are now included in the cost of purchased power (see reference to deferral accounting above). Increased pensions and OPEB mark-to-market adjustment charges were due to higher net actuarial losses in 2011 as compared to 2010. The amortization of regulatory assets increased by $97 million in 2011 primarily due to reduced NUG deferrals as a result of lower Transitional Energy Facility Assessment and sales taxes.the PPUC-approved increase in Penelec’s NUG cost recovery rider in January 2011.

METROPOLITAN EDISON COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
Met-Ed is a wholly owned electric utility subsidiary of FirstEnergy. Met-Ed provides regulated electric transmission and distribution services in 3,300 square miles of eastern and south central Pennsylvania. The area it serves has a population of approximately 1.2 million. Met-Ed also procures generation service for those franchise customers who have elected to retain them as their power supplier. Met-Ed procures power under its DSP, in which full requirements products (energy, capacity, ancillary services, and applicable transmission services) are procured through descending clock auctions.
For additional information with respect to Met-Ed, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Contractual Obligations, Off-Balance Sheet Arrangements, Regulatory Matters, Environmental Matters, Other ExpensesLegal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.

On January 25, 2012, Met-Ed filed a Form 15 with the SEC to deregister its securities and suspend its obligation to file periodic reports under the Securities Exchange Act of 1934, as amended, except that the registrant has filed this Annual Report on Form 10-K for the year ended December 31, 2011. This Annual Report on Form 10-K will be the last filing made by Met-Ed with the SEC under the Exchange Act.
Results of Operations
Other expensesNet income increased by $12$8 million in 20092011 compared to 20082010. The increase was primarily due to decreased purchased power costs, other operating expenses and amortization of net regulatory assets partially offset by decreased revenues.
Revenues
Revenue decreased $606 million, or 33%, in 2011 compared to 2010, reflecting lower distribution, retail generation, wholesale generation and transmission revenues.
Distribution revenues decreased $336 million in 2011 compared to 2010, primarily due to lower rates resulting from the DSP that began in 2011 that eliminated the transmission component from the distribution rates. The lower MWH deliveries to residential and commercial customers were influenced by decreased weather-related usage in 2011. In the industrial sector, MWH deliveries increased primarily as a result of recovering economic conditions in Met-Ed's service territory.
Changes in distribution MWH deliveries and revenues in 2011 compared to 2010 are summarized in the following tables:
Distribution MWH DeliveriesIncrease (Decrease)
Residential(1.4)%
Commercial(2.0)%
Industrial2.2 %
Net Decrease in Distribution Deliveries(0.2)%
Distribution Revenues Decrease
  (In millions)
Residential $(133)
Commercial (90)
Industrial (113)
Decrease in Distribution Revenues $(336)
In 2011, retail generation revenues decreased $52 million due to lower MWH sales to all customer classes resulting from increased customer shopping. The impact of increased customer shopping is partially offset by higher interest expense associated with JCP&L's $300 million Senior Notes issuancegeneration rates that reflect the inclusion of transmission services under the DSP, effective January 1, 2011, for all customer classes. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. In 2011, Met-Ed began deferring the difference between retail generation revenues and purchased power costs, resulting in January 2009.no material effect to current period earnings.


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Changes in retail generation MWH sales and revenues in 2011 compared to 2010 are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(3.8)%
Commercial(49.1)%
Industrial(91.8)%
Net Decrease in Retail Generation Sales(45.7)%
Retail Generation Revenues Increase (Decrease)
  (In millions)
Residential $166
Commercial (24)
Industrial (194)
Net Decrease in Retail Generation Revenues $(52)
Wholesale revenues decreased $210 million in 2011 compared to 2010, primarily reflecting lower RPM revenues for Met-Ed in the PJM market.
Transmission revenues decreased $9 million in 2011 compared to 2010 primarily due to the termination of InvestmentMet-Ed’s TSC rates effective January 1, 2011. Met-Ed deferred the difference between transmission revenues and transmission costs incurred, resulting in no material effect to earnings in the period.

Operating Expenses
On April 17, 2008, JCP&L closed on the sale of its 86-MW Forked River Power PlantTotal operating expenses decreased $608 million in 2011 compared to Maxim Power Corp. for $20 million, as approved by an earlier order2010. The following table presents changes from the NJBPU.prior year by expense category:
Operating Expenses - Changes Increase (Decrease)
  (In millions)
Purchased power costs $(328)
Other operating costs (230)
Pensions and OPEB mark-to-market adjustment 26
Provision for depreciation 5
Amortization of regulatory assets, net (68)
General taxes (13)
Net Decrease in Operating Expenses $(608)
Purchased power costs decreased $328 million in 2011 compared to 2010 due to a decrease in MWH purchased to source generation sales requirements, partially offset by higher unit costs. Decreased power purchased from affiliates reflects the increase in customer shopping described above and the termination of Met-Ed's partial requirements PSA with FES at the end of 2010. Other operating costs decreased $230 million in 2011 compared to 2010 due to lower transmission congestion and transmission loss expenses that are now included in the cost of purchased power (see reference to deferral accounting above), partially offset by increased costs for energy efficiency programs. Increased pensions and OPEB mark-to-market adjustment changes were due to higher net actuarial losses in 2011 as compared to 2010. The New Jersey Rate Counsel appealed the saleamortization of regulatory assets decreased $68 million in 2011 compared to 2010 primarily due to the Appellate Divisiontermination of transmission and transition tariff riders at the Superior Courtend of New Jersey. On July 10, 2009, the Court upheld the NJBPU’s order and the sale of the plant.2010. General taxes decreased by $13 million in 2011 primarily due to lower gross receipts taxes.

Other Expense
Interest income decreased by $3 million in 2011 compared to 2010 primarily due to reduced CTC stranded asset balances.
Market Risk Information

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


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Commodity Price Risk

JCP&LMet-Ed is exposed to market risk primarily due to fluctuations infinancial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, energy transmission and natural gas prices. To manageand energy transmission. FirstEnergy's Risk Policy Committee is responsible for promoting the volatility relating to these exposures, JCP&Leffective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. Met-Ed uses a variety of non-derivative and derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. The majority of JCP&L’s derivative contracts must be recorded at their fair value and marked to market. Power purchase agreements with NUG entities that were structured pursuant to the Public Utility Regulatory Policies Act of 1978 are non-trading contracts and 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 2009 is summarized in the following table:

Increase (Decrease) in the Fair Value of Derivative Contracts
 Non-Hedge  Hedge  Total 
  (In millions) 
Change in the fair value of commodity derivative contracts:         
Outstanding net liability as of January 1, 2009
 $(510) $-  $(510)
Additions/change in value of existing contracts
  (43)  -   (43)
Settled contracts
  167   -   167 
Outstanding net liability as of December 31, 2009(1)
 $(386) $-  $(386)
             
Impact of changes in commodity derivative contracts(2)
            
Income Statement effects (Pre-Tax)
 $-  $-  $- 
Balance Sheet effects:
            
OCI (Pre-Tax)
 $-  $-  $- 
Regulatory Asset (net)
 $(124) $-  $(124)

(1)Includes $386 million in non-hedge commodity derivative contracts (primarily with NUGs) that are subject to regulatory accounting and do not impact earnings.
(2)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 December 31, 2009 as follows:

 
Balance Sheet Classification
 Non-Hedge  Hedge  Total 
  (In millions) 
Non-Current-
         
Other deferred charges
 $13  $-  $13 
Other noncurrent liabilities
  (399)  -   (399)
Net liabilities
 $(386) $-  $(386)

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, JCP&LMet-Ed relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. JCP&LMet-Ed uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making.making (see Note 9, Fair Value Measurements of the Combined Notes to the Consolidated Financial Statements). Sources of information for the valuation of commodity derivative contractscontract assets and liabilities as of December 31, 20092011, 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) 
Other external sources(1)
  $(157) $(110) $(45) $(41) $-  $-  $(353)
Prices based on models   -   -   -   -   (27)  (6)  (33)
Total(2)
  $(157) $(110) $(45) $(41) $(27) $(6) $(386)
Source of Information-
Fair Value by Contract Year
 2012 2013 2014 2015 2016 Thereafter Total
  (In millions)
Prices actively quoted(1)
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Other external sources(2)
 (62) (7) (6) (5) —
 —
 (80)
Prices based on models —
 —
 —
 —
 8
 42
 50
Total(3)
 $(62) $(7) $(6) $(5) $8
 $42
 $(30)

(1)
Broker quote sheets.Represents exchange traded New York Mercantile Exchange futures and options.
(2)
Primarily represents contracts based on broker and IntercontinentalExchange quotes.
(3)
Includes $386$(30) million in non-hedge commodity derivative contracts (primarily with NUGs) that are related to NUG contracts. NUG contracts are subject to regulatory accounting and do not materially impact earnings.

JCP&LMet-Ed performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift in quoted market prices in the near term on derivative instruments would not have had a material effect on JCP&L’s consolidated financial position or cash flows as of December 31, 2009. Based on derivative contracts held as of December 31, 2009,2011, an adverse 10% change in commodity prices would not have a material effect on JCP&L’sMet-Ed’s net income for the next 12 months.

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Interest Rate Risk
JCP&L’sMet-Ed’s exposure to fluctuations in market interest rates is reduced since a significant portion of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for JCP&L’sMet-Ed’s investment portfolio and debt obligations.
Comparison of Carrying Value to Fair ValueComparison of Carrying Value to Fair Value Comparison of Carrying Value to Fair Value
          There-   Fair 
Year of Maturity2010 2011 2012 2013 2014 after Total Value  2012 2013 2014 2015 2016 There-after Total Fair Value
Assets(Dollars in millions) 
 (In millions)
Assets:          
Investments Other Than Cash
and Cash Equivalents:
                          
Fixed Income                     $270  $270  $280      $234
 $234
 $234
Average interest rate                      3.8%  3.8%         3.3% 3.3%  
                                
Liabilities                                
Liabilities:          
Long-term Debt:                                          
Fixed rate $31  $32  $34  $36  $38  $1,669  $1,840  $1,950  $150
 $250
 $300
 $700
 $796
Average interest rate  5.4%  5.6%  5.7%  5.7%  5.9%  6.1%  6.0%     5.0% 4.9% 7.7% 6.1%  
Variable rate     $29
 $29
 $29
Average interest rate     0.1% 0.1%  

Equity Price Risk
NDT funds have been established to satisfy nuclear decommissioning obligations. Included in JCP&L’s nuclear decommissioning trustsMet-Ed’s NDT are marketable equity securitiesfixed income, equities and short-term investments carried at their market valuevalues of approximately $85$234 million, $51 million and $23 million, respectively, as of December 31, 2009.2011, excluding $2 million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $9$5 million reduction in fair value as of December 31, 2009 (see Note 5)2011. Met-Ed's NDT is 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. A decline


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in the value of Met-Ed's NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements.
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. Met-Ed evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. Met-Ed may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. Met-Ed monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.


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PENNSYLVANIA ELECTRIC COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec provides regulated electric transmission and distribution services in 17,600 square miles of western, northern and south central Pennsylvania. The area it serves has a population of approximately 1.3 million. Penelec, as lessee of the property of its subsidiary, The Waverly Electric Light & Power Company, serves customers in the Waverly, New York vicinity. Penelec also procures generation service for those franchise customers who have elected to retain them as their power supplier. Penelec procures power under its DSP, in which full requirements products (energy, capacity, ancillary services and applicable transmission services) are procured through descending clock auctions.
For additional information with respect to Penelec, 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: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Contractual Obligations, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
On January 25, 2012, Penelec filed a Form 15 with the SEC to deregister its securities and suspend its obligation to file periodic reports under the Securities Exchange Act of 1934, as amended, except that the registrant has filed this Annual Report on Form 10-K for the year ended December 31, 2011. This Annual Report on Form 10-K will be the last filing made by Penelec with the SEC under the Exchange Act.
Results of Operations
Net income was unchanged in 2011, compared to 2010, due to lower purchased power costs, other operating expenses and income taxes, partially offset by lower revenues and higher amortization of regulatory assets.
Revenues
Revenues decreased by $459 million, or 30%, in 2011 compared to 2010. The decrease in revenue was primarily due to lower distribution, retail generation, wholesale generation and transmission revenues.
Distribution revenues decreased by $93 million in 2011, compared to 2010, primarily due to lower rates resulting from the DSP, which eliminated the transmission component from the distribution rate beginning in 2011, partially offset by a PPUC-approved rate adjustment for NUG costs. Lower MWH deliveries to residential and commercial customers reflected decreased weather-related usage compared to 2010. Higher MWH deliveries to industrial customers were primarily due to recovering economic conditions in Penelec’s service territory, compared to 2010.
Changes in distribution MWH deliveries and revenues in 2011, compared to 2010, are summarized in the following tables:
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Distribution MWH Deliveries
Increase
(Decrease)
Residential(2.2)%
Commercial(3.7)%
Industrial4.5 %
Net Decrease in Distribution Deliveries0.1 %
Distribution Revenues Decrease
  (In millions)
Residential $(35)
Commercial (31)
Industrial (27)
Decrease in Distribution Revenues $(93)

Retail generation revenues decreased by $218 million in 2011, compared to 2010, due to lower MWH sales in all customer classes resulting from increased customer shopping. The impact of customer shopping was partially offset by higher generation rates that reflect the inclusion of transmission services under the DSP, effective January 1, 2011, for all customer classes. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. In 2011, Penelec began deferring the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings.


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Changes in retail generation MWH sales and revenues in 2011, compared to 2010, are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(8.5)%
Commercial(53.6)%
Industrial(92.5)%
Decrease in Retail Generation Sales(53.1)%
Retail Generation Revenues 
Increase
(Decrease)
  (In millions)
Residential $87
Commercial (78)
Industrial (227)
Net Decrease in Retail Generation Revenues $(218)

Wholesale generation revenues decreased by $205 million in 2011, compared to 2010, reflecting lower RPM revenues for Penelec in the PJM market.
Transmission revenues decreased by $7 million in 2011, compared to 2010, primarily due to the termination of Penelec’s TSC rates effective January 1, 2011. Penelec deferred the difference between transmission revenues and transmission costs incurred, resulting in no material effect to earnings for the period.
Operating Expenses

Total operating expenses decreased by $446 million in 2011 as compared to 2010. The following table presents changes from the prior year by expense category:
Operating Expenses - Changes Increase (Decrease)
  (In millions)
Purchased power costs (467)
Other operating costs (99)
Pensions and OPEB mark-to-market adjustment 33
Provision for depreciation (3)
Amortization of regulatory assets, net 97
General taxes (7)
Net Decrease in Operating Expenses $(446)

Purchased power costs decreased by $467 million in 2011, compared to 2010, due to a decrease in MWH purchased to source generation sales requirements. Decreased power purchased from affiliates resulted from reduced requirements due to the increase in customer shopping described above and the termination of Penelec's partial requirements PSA with FES at the end of 2010. Other operating costs decreased by $99 million in 2011 due to lower transmission congestion and transmission loss expenses that are now included in the cost of purchased power (see reference to deferral accounting above). Increased pensions and OPEB mark-to-market adjustment charges were due to higher net actuarial losses in 2011 as compared to 2010. The amortization of regulatory assets increased by $97 million in 2011 primarily due to reduced NUG deferrals as a result of the PPUC-approved increase in Penelec’s NUG cost recovery rider in January 2011.
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, providingprovides regulated electric transmission and distribution services.services in 3,300 square miles of eastern and south central Pennsylvania. The area it serves has a population of approximately 1.2 million. Met-Ed also providesprocures generation service tofor those franchise customers electingwho have elected to retain Met-Edthem as their power supplier. On November 3, 2009, FES, Met-Ed Penelecprocures power under its DSP, in which full requirements products (energy, capacity, ancillary services, and Waverly restated their partial requirements power purchase agreement for 2010. Under the new agreement, Met-Ed, Penelec, and Waverly assigned 1,300 MW of existing energy purchases to FES to assist it in supplying Met-Ed's power supply requirements and managing congestion expenses.
applicable transmission services) are procured through descending clock auctions.
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:subheadings: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Guarantees and Other Assurances, Strategy and Outlook,Contractual Obligations, Off-Balance Sheet Arrangements, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
On January 25, 2012, Met-Ed filed a Form 15 with the SEC to deregister its securities and suspend its obligation to file periodic reports under the Securities Exchange Act of 1934, as amended, except that the registrant has filed this Annual Report on Form 10-K for the year ended December 31, 2011. This Annual Report on Form 10-K will be the last filing made by Met-Ed with the SEC under the Exchange Act.
Results of Operations
In 2009, Met-Ed reported netNet income of $56increased by $8 million in 2011 compared to $88 million 2008.2010. The decreaseincrease was primarily due to decreased distribution throughputpurchased power costs, other operating expenses and generation sales, and increased interest expense,amortization of net regulatory assets partially offset by lower other operating costs and higher transmission rates.
decreased revenues.
Revenues
Revenues increased by $36Revenue decreased $606 million, or 2.2%33%, in 20092011 compared to 2008 principally due to higher2010, reflecting lower distribution, andretail generation, wholesale generation revenues, partially offset by a decrease in retail generation and PJM transmission revenues.
Revenues from distribution increased $88Distribution revenues decreased $336 million in 20092011 compared to 20082010, primarily due to higher transmissionlower rates resulting from the annual update of Met-Ed’s TSC rider effective June 1, 2009. Decreased KWH deliveries to commercial and industrial customers reflectingDSP that began in 2011 that eliminated the weakened economy, while decreasedtransmission component from the distribution rates. The lower MWH deliveries to residential and commercial customers were influenced by decreased weather-related usage in 2011. In the industrial sector, MWH deliveries increased primarily as a result of weather-related usage variations from a 14.2% decreaserecovering economic conditions in cooling degree days for 2009 compared to 2008.Met-Ed's service territory.
Changes in distribution KWHMWH deliveries and revenues in 20092011 compared to 20082010 are summarized in the following tables:

Distribution KWHMWH Deliveries Increase (Decrease)
   
Residential (2.71.4)%
Commercial (4.42.0)%
Industrial 2.2(10.3)%
Net Decrease in Distribution Deliveries (5.30.2)%


Distribution RevenuesIncrease
(In millions)
Residential $43
Commercial28
Industrial17
Increase in Distribution Revenues $88

Wholesale revenues increased by $15 million in 2009 compared to 2008, primarily reflecting higher PJM spot market prices.
Distribution Revenues Decrease
  (In millions)
Residential $(133)
Commercial (90)
Industrial (113)
Decrease in Distribution Revenues $(336)
In 2009,2011, retail generation revenues decreased $35$52 million due to lower KWHMWH sales into all customer classes with composite unit pricesresulting from increased slightlycustomer shopping. The impact of increased customer shopping is partially offset by higher generation rates that reflect the inclusion of transmission services under the DSP, effective January 1, 2011, for residentialall customer classes. Retail generation obligations are attributable to non-shopping customers and commercial customer classes and decreased slightly for industrial customers. 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 as discussed above.

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Changes in retailare satisfied by generation sales and revenues in 2009 compared to 2008 are summarized in the following tables:

Retail Generation KWH Sales(Decrease)
Residential(2.7)%
Commercial(4.4)%
Industrial(10.4)%
Decrease in Retail Generation Sales(5.3)%
Retail Generation Revenues(Decrease)
(In millions)
Residential $(7)
Commercial(10)
Industrial(18)
Decrease in Retail Generation Revenues $(35)

procured through full-requirements auctions. In Transmission service revenues decreased by $31 million in 2009 compared to 2008 primarily due to decreased revenues related to Met-Ed's Financial Transmission Rights.2011, Met-Ed defersbegan deferring the difference between transmissionretail generation revenues and net transmissionpurchased power costs, incurred, resulting in no material effect to current period earnings.


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Changes in retail generation MWH sales and revenues in 2011 compared to 2010 are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(3.8)%
Commercial(49.1)%
Industrial(91.8)%
Net Decrease in Retail Generation Sales(45.7)%
Retail Generation Revenues Increase (Decrease)
  (In millions)
Residential $166
Commercial (24)
Industrial (194)
Net Decrease in Retail Generation Revenues $(52)
Wholesale revenues decreased $210 million in Expenses2011 compared to 2010, primarily reflecting lower RPM revenues for Met-Ed in the PJM market.
Transmission revenues decreased $9 million in 2011 compared to 2010 primarily due to the termination of Met-Ed’s TSC rates effective January 1, 2011. Met-Ed deferred the difference between transmission revenues and transmission costs incurred, resulting in no material effect to earnings in the period.
Operating Expenses
Total operating expenses increased by $84decreased $608 million in 20092011 compared to 2008.2010. The following table presents changes from the prior year by expense category:

 Increase 
Expenses – Changes (Decrease) 
Operating Expenses - Changes Increase (Decrease)
 (In millions)  (In millions)
Purchased power costs $4  $(328)
Other operating costs  (152) (230)
Pensions and OPEB mark-to-market adjustment 26
Provision for depreciation  7  5
Amortization of regulatory assets, net  223  (68)
General taxes  2  (13)
Net increase in expenses $84 
Net Decrease in Operating Expenses $(608)

Purchased power costs increased by $4decreased $328 million in 20092011 compared to 20082010 due to an increasea decrease in unit costs,MWH purchased to source generation sales requirements, partially offset by reduced volumeshigher unit costs. Decreased power purchased as a resultfrom affiliates reflects the increase in customer shopping described above and the termination of lower KWH sales requirements.Met-Ed's partial requirements PSA with FES at the end of 2010. Other operating costs decreased $152$230 million in 20092011 compared to 2010 due primarily to lower transmission expenses as a result of decreased congestion costs and transmission loss expenses that are now included in the cost of purchased power (see reference to deferral accounting above), partially offset by higher employee benefit expenses. Depreciation expense increased generallycosts for energy efficiency programs. Increased pensions and OPEB mark-to-market adjustment changes were due to an increasehigher net actuarial losses in depreciable property since the end of 2008.2011 as compared to 2010. The net amortization of regulatory assets increased by $223decreased $68 million in 2009 resulting from increased transmission cost recovery. In 2009, general taxes increased2011 compared to 2010 primarily due to higherthe termination of transmission and transition tariff riders at the end of 2010. General taxes decreased by $13 million in 2011 primarily due to lower gross receipts taxes resulting from increased sales revenues.
Other Expensetaxes.
Other expense increased $17Expense
Interest income decreased by $3 million in 2009 resulting from2011 compared to an increase in interest expense from Met-Ed’s $300 million Senior Notes issuance in January 2009. In addition, less interest income was earned in 2009 on2010 primarily due to reduced CTC stranded regulatory assets, reflecting lower regulatory asset balances.
Market Risk Information
Met-Ed uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.


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Commodity Price Risk
Met-Ed is exposed to market risk primarily due to fluctuations infinancial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, energy transmission and natural gas prices. To manageand energy transmission. FirstEnergy's Risk Policy Committee is responsible for promoting the volatility relating to these exposures,effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. Met-Ed uses a variety of non-derivative and derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. The majority of Met-Ed’s derivative contracts must be recorded at their fair value and marked to market. Certain derivative hedging contracts qualify for the normal purchase and normal sale exception and are therefore excluded from the table below. Contracts that are not exempt from such treatment include 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 2009 is summarized in the following table:

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Increase (Decrease) in the Fair Value of Derivative Contracts Non-Hedge  Hedge  Total 
  (In millions) 
Change in the Fair Value of Commodity Derivative Contracts         
Outstanding net liabilities as of January 1, 2009 $164  $-  $164 
Additions/Changes in value of existing contracts  (205)  -   (205)
Settled contracts  83   -   83 
Net Assets - Derivative Contracts as of December 31, 2009(1)
 $42  $-  $42 
             
Impact of Changes in Commodity Derivative Contracts(2)
            
Income Statement Effects (Pre-Tax) $-  $-  $- 
Balance Sheet Effects:            
Regulatory Liability (net)
 $122  $-  $122 

(1)Includes $42 million in non-hedge commodity derivative contracts (primarily with NUGs) that are subject to regulatory accounting and do not impact earnings.
(2)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 December 31, 2009 as follows:

  Non-Hedge  Hedge  Total 
  (In millions) 
Non-Current-
         
Other deferred charges $185  $-  $185 
Other noncurrent liabilities  (143)  -   (143)
             
Net assets
 $42  $-  $42 

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, Met-Ed relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Met-Ed uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making.making (see Note 9, Fair Value Measurements of the Combined Notes to the Consolidated Financial Statements). Sources of information for the valuation of commodity derivative contractscontract assets and liabilities as of December 31, 20092011, 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) 
Other external sources(1)
 $(50) $(42) $(38) $2  $-  $-  $(128)
Prices based on models  -   -   -   -   25   145   170 
Total(2)
 $(50) $(42) $(38) $2  $25  $145  $42 
Source of Information-
Fair Value by Contract Year
 2012 2013 2014 2015 2016 Thereafter Total
  (In millions)
Prices actively quoted(1)
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Other external sources(2)
 (62) (7) (6) (5) —
 —
 (80)
Prices based on models —
 —
 —
 —
 8
 42
 50
Total(3)
 $(62) $(7) $(6) $(5) $8
 $42
 $(30)

(1)
Broker quote sheets.Represents exchange traded New York Mercantile Exchange futures and options.
(2)
Primarily represents contracts based on broker and IntercontinentalExchange quotes.
(3)
Includes $42$(30) million in non-hedge commodity derivative contracts (primarily with NUGs) that are related to NUG contracts. NUG contracts are subject to regulatory accounting and do not materially impact earnings.

Met-Ed performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift in quoted market prices in the near term on derivative instruments would not have had a material effect on Met-Ed’s consolidated financial position or cash flows as of December 31, 2009. Based on derivative contracts held as of December 31, 2009,2011, an adverse 10% change in commodity prices would not have a material effect on Met-Ed’s net income for the next 12 months.
Interest Rate Risk
Met-Ed’s exposure to fluctuations in market interest rates is reduced since a significant portion of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for Met-Ed’s investment portfolio and debt obligations.

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Comparison of Carrying Value to Fair ValueComparison of Carrying Value to Fair Value Comparison of Carrying Value to Fair Value
            There   Fair 
Year of Maturity 2010  2011  2012 2013 2014 after Total Value  2012 2013 2014 2015 2016 There-after Total Fair Value
(Dollars in millions) (In millions)
Assets                  
Assets:          
Investments Other Than Cash
and Cash Equivalents:
                            
Fixed Income                     $120  $120  $125      $234
 $234
 $234
Average interest rate                      2.1%  2.1%         3.3% 3.3%  
 
                                
Liabilities 
Liabilities:          
Long-term Debt:                                          
Fixed rate $100          $150  $250  $314  $814  $881  $150
 $250
 $300
 $700
 $796
Average interest rate  4.5%          5.0%  4.9%  7.6%  5.9%     5.0% 4.9% 7.7% 6.1%  
Variable rate                     $28  $28  $28      $29
 $29
 $29
Average interest rate                      0.2%  0.2%         0.1% 0.1%  
Equity Price Risk
NDT funds have been established to satisfy nuclear decommissioning obligations. Included in Met-Ed’s nuclear decommissioning trustsNDT are marketable equity securitiesfixed income, equities and short-term investments carried at their market valuevalues of approximately $140$234 million, $51 million and $23 million, respectively, as if of December 31, 2009.2011, excluding $2 million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in an $14a $5 million reduction in fair value as of December 31, 2009 (see Note 5)2011. Met-Ed's NDT is 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. A decline


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in the value of Met-Ed's NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements.
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. Met-Ed evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. Met-Ed may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. Met-Ed monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.


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PENNSYLVANIA ELECTRIC COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts businessprovides regulated electric transmission and distribution services in 17,600 square miles of western, northern and south central Pennsylvania, providing regulated transmission and distribution services.Pennsylvania. The area it serves has a population of approximately 1.3 million. Penelec, as lessee of the property of its subsidiary, The Waverly Electric Light & Power Company, serves customers in the Waverly, New York vicinity. Penelec also providesprocures generation services toservice for those franchise customers electingwho have elected to retain Penelecthem as their power supplier. On November 3, 2009, Penelec Met-Edprocures power under its DSP, in which full requirements products (energy, capacity, ancillary services and Waverly restated their partial requirements power purchase agreement for 2010. Under the new agreement, Penelec, Met-Ed, and Waverly assigned 1,300 MW of existing energy purchases to FES to assist it in supplying Buyers’ power supply requirements and managing congestion expenses.
applicable transmission services) are procured through descending clock auctions.
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: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Guarantees and Other Assurances and Outlook: Capital Resources and Liquidity, Guarantees and Other Assurances, Strategy and Outlook,Contractual Obligations, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
On January 25, 2012, Penelec filed a Form 15 with the SEC to deregister its securities and suspend its obligation to file periodic reports under the Securities Exchange Act of 1934, as amended, except that the registrant has filed this Annual Report on Form 10-K for the year ended December 31, 2011. This Annual Report on Form 10-K will be the last filing made by Penelec with the SEC under the Exchange Act.
Results of Operations
Net income decreased to $65 millionwas unchanged in 2009,2011, compared to $88 million in 2008. The decrease was primarily2010, due to lower purchased power costs, other operating expenses and income taxes, partially offset by lower revenues and higher purchased power costs, partially offset by lower other operating costs and decreased amortization of regulatory assets.
Revenues
Revenues decreaseddecreased by $65$459 million, or 4.3%30%, in 20092011 compared to 20082010. The decrease in revenue was primarily due to lower transmission,distribution, retail generation, wholesale generation and transmission revenues.
Distribution revenues decreased by $93 million in 2011, compared to 2010, primarily due to lower rates resulting from the DSP, which eliminated the transmission component from the distribution rate beginning in 2011, partially offset by a PPUC-approved rate adjustment for NUG costs. Lower MWH deliveries to residential and commercial customers reflected decreased weather-related usage compared to 2010. Higher MWH deliveries to industrial customers were primarily due to recovering economic conditions in Penelec’s service territory, compared to 2010.
Changes in distribution MWH deliveries and revenues in 2011, compared to 2010, are summarized in the following tables:
Distribution MWH Deliveries
Increase
(Decrease)
Residential(2.2)%
Commercial(3.7)%
Industrial4.5 %
Net Decrease in Distribution Deliveries0.1 %
Distribution Revenues Decrease
  (In millions)
Residential $(35)
Commercial (31)
Industrial (27)
Decrease in Distribution Revenues $(93)

Retail generation revenues decreased by $218 million in 2011, compared to 2010, due to lower MWH sales in all customer classes resulting from increased customer shopping. The impact of customer shopping was partially offset by higher wholesale generation revenues.rates that reflect the inclusion of transmission services under the DSP, effective January 1, 2011, for all customer classes. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. In 2011, Penelec began deferring the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings.


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Changes in retail generation MWH sales and revenues in 2011, compared to 2010, are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(8.5)%
Commercial(53.6)%
Industrial(92.5)%
Decrease in Retail Generation Sales(53.1)%
Retail Generation Revenues 
Increase
(Decrease)
  (In millions)
Residential $87
Commercial (78)
Industrial (227)
Net Decrease in Retail Generation Revenues $(218)

Wholesale generation revenues decreased by $205 million in 2011, compared to 2010, reflecting lower RPM revenues for Penelec in the PJM market.
Transmission revenues decreased by $44$7 million in 20092011, compared to 2008,2010, primarily due to lower revenues related tothe termination of Penelec’s Financial Transmission Rights.TSC rates effective January 1, 2011. Penelec defersdeferred the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.earnings for the period.
In 2009, retail generation revenues decreased $37 million primarily due to lower KWH sales in all customer classes. Lower KWH sales to the commercial and industrial customer classes were primarily due to weakened economic conditions in Penelec’s service territory. Lower KWH sales to the residential customer class were due to decreased weather-related usage, reflecting a 28.5% decrease in cooling degree days in 2009 compared to 2008.
Changes in retail generation sales and revenues in 2009 as compared to 2008 are summarized in the following tables:Operating Expenses

Retail Generation KWH SalesDecrease
Residential(1.9)%
Commercial(3.2)%
Industrial(13.7)%
Decrease in Retail Generation Sales(5.9)%


Retail Generation Revenues Decrease 
  (In millions) 
Residential $(4)
Commercial  (8)
Industrial  (25)
Decrease in Retail Generation Revenues $(37)

Revenues from distribution throughput decreased $7 million in 2009 compared to 2008, primarily due to decreased deliveries to the commercial and industrial sectors reflecting the economic conditions in Penelec’s service area. Offsetting this decrease was an increase in residential unit prices due to an increase in transmission rates, resulting from the annual update of Penelec’s TSC rider effective June 1, 2009.

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Changes in distribution KWH deliveries and revenues in 2009 as compared to 2008 are summarized in the following tables:

Distribution KWH DeliveriesDecrease
Residential(1.9)%
Commercial(3.2)%
Industrial(12.0)%
Decrease in Distribution Deliveries(5.6)%


Distribution Revenues 
Increase
(Decrease)
 
  (In millions) 
Residential $2 
Commercial  (4)
Industrial  (5)
Net Decrease in Distribution Revenues $(7)

Wholesale revenues increased $19 million in 2009 compared to the same period in 2008, primarily reflecting higher KWH sales.
Expenses
Total operating expenses decreased by $22$446 million in 20092011 as compared to 2008.2010. The following table presents changes from the prior year by expense category:
Operating Expenses - Changes Increase (Decrease)
  (In millions)
Purchased power costs (467)
Other operating costs (99)
Pensions and OPEB mark-to-market adjustment 33
Provision for depreciation (3)
Amortization of regulatory assets, net 97
General taxes (7)
Net Decrease in Operating Expenses $(446)

Expenses - Changes 
Increase
(Decrease)
 
  (In millions) 
Purchased power costs $11 
Other operating costs  (19)
Provision for depreciation  7 
Amortization of regulatory assets, net  (15)
General taxes  (6)
Net Decrease in expenses $(22)

Purchased power costs increaseddecreased by $11$467 million in 20092011, compared to 2008, primarily2010, due to higher unit costs, partially offset bya decrease in MWH purchased to source generation sales requirements. Decreased power purchased from affiliates resulted from reduced volume as a resultrequirements due to the increase in customer shopping described above and the termination of lower KWH sales requirements.Penelec's partial requirements PSA with FES at the end of 2010. Other operating costs decreased by $19$99 million in 20092011 due to lower transmission congestion and transmission loss expenses that are now included in the cost of purchased power (see reference to deferral accounting above). Increased pensions and OPEB mark-to-market adjustment charges were due to higher net actuarial losses in 2011 as compared to 2008, principally due to reduced transmission and labor costs, partially offset by higher pension and OPEB expenses. Depreciation expense increased primarily due to an increase in depreciable property since December 31, 2008.2010. The net amortization of regulatory assets decreasedincreased by $15$97 million in 2009 compared to 20082011 primarily due to increased transmission costreduced NUG deferrals as a result of increased net congestion costs. General taxesthe PPUC-approved increase in Penelec’s NUG cost recovery rider in January 2011.
Other Expenses
Other expenses decreased by $3 millionin 2009 primarily2011, compared to 2010, due to lower gross receipts tax as a result of the reduced KWH sales discussed above.
Other Expense
In 2009, other expense decreased by $8 million primarily due toincome from jobbing and contracting work and lower interest expense on borrowings from the regulated money pool and the Revolving Credit Facility, partially offset by an increase in interest expense on long-term debt due to the $500 million debt issuance on September 30, 2009.
capitalized interest.
Market Risk Information
Penelec uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight tofor risk management activities.activities throughout the company.



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128


Commodity Price Risk
Penelec is exposed to market risk primarily due to fluctuations infinancial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, energy transmission and natural gas prices. To manageand energy transmission. FirstEnergy's Risk Policy Committee is responsible for promoting the volatility relating to these exposures,effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. Penelec uses a variety of non-derivative and derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. The majority of Penelec’s derivative contracts must be recorded at their fair value and marked to market. Power purchase agreements with NUG entities that were structured pursuant to the Public Utility Regulatory Policies Act of 1978 are non-trading contracts and 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 2009 is summarized in the following table:

Increase (Decrease) in the Fair Value of Derivative Contracts Non-Hedge  Hedge  Total 
  (In millions) 
Change in the Fair Value of Commodity Derivative Contracts         
Outstanding net liabilities as of January 1, 2009 $43  $-  $43 
Additions/Changes in value of existing contracts  (223)  -   (223)
Settled contracts  99   -   99 
Net Assets - Derivative Contracts as of December 31, 2009(1)
 $(81) $-  $(81)
             
Impact of Changes in Commodity Derivative Contracts(2)
            
Income Statement Effects (Pre-Tax) $-  $-  $- 
Balance Sheet Effects:            
Regulatory Liability (net) $124  $-  $124 

(1)Includes $81 million in non-hedge commodity derivative contracts (primarily with NUGs) that are subject to regulatory accounting and do not impact earnings.
(2)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 December 31, 2009 as follows:

  Non-Hedge  Hedge  Total 
  (In millions) 
Non-Current-
         
Other deferred charges $20  $-  $20 
Other noncurrent liabilities  (101)  -   (101)
Net assets
 $(81) $-  $(81)

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, Penelec relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Penelec uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making.making (see Note 9, Fair Value Measurements of the Combined Notes to the Consolidated Financial Statements). Sources of information for the valuation of commodity derivative contractscontract assets and liabilities as of December 31, 20092011, 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) 
Other external sources(1)
 $(51) $(55) $(56) $(5) $-  $-  $(167)
Prices based on models  -   -   -   -   13   73   86 
Total(2)
 $(51) $(55) $(56) $(5) $13  $73  $(81)
Source of Information-
Fair Value by Contract Year
 2012 2013 2014 2015 2016 Thereafter Total
  (In millions)
Prices actively quoted(1)
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Other external sources(2)
 (85) (12) (10) (11) —
 —
 (118)
Prices based on models —
 —
 —
 —
 1
 (3) (2)
Total(3)
 $(85) $(12) $(10) $(11) $1
 $(3) $(120)

(1)
Broker quote sheet.Represents exchange traded New York Mercantile Exchange futures and options.
(2)
(2)
Primarily represents contracts based on broker and IntercontinentalExchange quotes.
(3)
Includes $81 million$(120) million in non-hedge commodity derivative contracts (primarily with NUGs) that are related to NUG contracts. NUG contracts are subject to regulatory accounting and do not materially impact earnings.

Penelec performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift in quoted market prices in the near term on derivative instruments would not have had a material effect on Penelec’s consolidated financial position or cash flows as of December 31, 2009. Based on derivative contracts held as of December 31, 2009,2011, an adverse 10% change in commodity prices would not have a material effect on Penelec’s net income for the next 12 months.

129
Interest Rate Risk
Penelec’s exposure to fluctuations in market interest rates is reduced since a significant portion of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for Penelec’s investment portfolio and debt obligations.
Comparison of Carrying Value to Fair ValueComparison of Carrying Value to Fair Value Comparison of Carrying Value to Fair Value
            There-   Fair 
Year of Maturity 2010  2011 2012  2013 2014 after Total Value  2012 2013 2014 2015 2016 There-after Total Fair Value
(Dollars in millions)  (In millions)
Assets                  
Assets:        
Investments Other Than Cash
and Cash Equivalents:
                          
Fixed Income                     $166  $166  $171    $195
 $195
 $195
Average interest rate                      3.0%  3.0%       3.8% 3.8%  
 
                                
Liabilities 
Liabilities:        
Long-term Debt:                                        
Fixed rate $24              $150  $925  $1,099  $1,132  $150
 $925
 $1,075
 $1,206
Average interest rate  5.4%              5.1%  5.9%  5.8%     5.1% 5.9% 5.8%  
Variable rate                     $45  $45  $45    $45
 $45
 $45
Average interest rate                      0.3%  0.3%       0.1% 0.1%  
Short-term Borrowings: $41                      $41  $41 
Average interest rate  0.7%                      0.7%    

Equity Price Risk
NDT funds have been established to satisfy nuclear decommissioning obligations. Included in Penelec’s nuclear decommissioning trusts NDT are marketable equity securitiesfixed income, equities and short-term investments carried at their market valuevalues of approximately $70$106 million, $26 million and $33 million, respectively, as of December 31, 2008.2011, excluding $1 million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $7$3 million reduction in fair value as of December 31, 2008 (see Note 5)2011. Penelec's NDT is 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. A decline


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130

in the value of Penelec's NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements.
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. Penelec evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. Penelec may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. Penelec monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.


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ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by ITEM 7A relating to market risk is set forth in ITEM 7. ManagementManagement's Discussion and Analysis of Financial Condition and Results of Operations.Operations.


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ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
MANAGEMENT REPORTS
Management's Responsibility for Financial Statements
The consolidated financial statements of FirstEnergy Corp. (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2009 consolidated financial statements.
The Company’s internal auditors, who are responsible to the Audit Committee of the Company’s Board of Directors, review the results and performance of operating units within the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.
The Company’s Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm's report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm's independence. The Committee also reviews management’s programs to monitor compliance with the Company’s policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held nine meetings in 2009.
Management's Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework, management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting under the supervision of the chief executive officer and the chief financial officer. Based on that evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2009. The effectiveness of the Company’s internal control over financial reporting, as of December 31, 2009, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page 142.

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ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
MANAGEMENT REPORTSOHIO EDISON COMPANY
MANAGEMENT’S NARRATIVE
Management's Responsibility for Financial StatementsANALYSIS OF RESULTS OF OPERATIONS
The consolidated financial statementsOE is a wholly owned electric utility subsidiary of FirstEnergy Solutions Corp. (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally acceptedFirstEnergy. OE engages in the United Statesdistribution and sale of electric energy to communities in a 7,000 square mile area of central and northeastern Ohio and, through its wholly owned subsidiary, Penn, 1,100 square miles in western Pennsylvania. OE and Penn conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services and procurement of generation services for those franchise customers electing to retain them as their power supplier. The areas served by OE and Penn have populations of approximately 2.3 million and 0.4 million, respectively.
For additional information with respect to OE, 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: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Contractual Obligations, Off-Balance Sheet Arrangements, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
Results of Operations
Net income decreased by $27 million in 2011 compared to 2010. The decrease primarily resulted from lower revenues and higher other operating expenses, partially offset by lower purchased power costs.
Revenues
Revenues decreased by $203 million, or 11%, in 2011 compared with 2010 due to lower retail generation revenues, partially offset by higher distribution and wholesale generation revenues.
Distribution revenues increased by $69 million in 2011, compared to 2010, due to increased MWH deliveries and higher average prices in all customer classes. The higher MWH deliveries in the residential class were driven primarily by increased load growth partially offset by lower weather-related usage. The increase in distribution deliveries to commercial and industrial customers was primarily due to recovering economic conditions in OE’s and Penn’s service territories. Higher average prices in all customer classes were principally due to the recovery of deferred distribution costs.
Changes in distribution MWH deliveries and revenues in 2011 compared to 2010, are summarized in the following tables:
Distribution MWH DeliveriesIncrease
Residential0.3%
Commercial0.7%
Industrial5.4%
Increase in Distribution Deliveries2.0%
Distribution Revenues Increase
  (In millions)
Residential $26
Commercial 17
Industrial 26
Increase in Distribution Revenues $69

Retail generation revenues decreased by $277 million primarily due to a decrease in MWH sales from increased customer shopping and lower average prices in all customer classes. Retail generation obligations are attributable to non-shopping customers and are consistentsatisfied by generation procured through full-requirements auctions. OE and Penn defer the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings. Lower MWH sales were primarily the result of increased customer shopping in 2011. The increases in shopping by residential, commercial and industrial customers were 18%, 11% and 7%, respectively, in 2011 compared with 2010.


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Decreases in retail generation MWH sales and revenues in 2011 compared to 2010 are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(28.8)%
Commercial(34.0)%
Industrial(22.6)%
Decrease in Retail Generation Sales(28.3)%
Retail Generation Revenues Decrease
  (In millions)
Residential $(166)
Commercial (74)
Industrial (37)
Decrease in Retail Generation Revenues $(277)

Wholesale generation revenues increased by $12 million in 2011 compared to 2010 due to higher revenues from sales to NGC from OE’s leasehold interests in Perry Unit 1 and Beaver Valley Unit 2.
Operating Expenses
Total operating expenses decreased by $175 million in 2011 compared to 2010. The following table presents changes from the prior year by expense category:
Operating Expenses - Changes Increase (Decrease)
  (In millions)
Purchased power costs $(279)
Other operating expenses 109
Pensions and OPEB mark-to-market adjustment 19
Provision for depreciation 2
Amortization of regulatory assets, net (33)
General taxes 7
Net Decrease in Operating Expenses $(175)

Purchased power costs decreased in 2011 compared to 2010 due to lower MWH purchases resulting from reduced generation sales requirements coupled with lower unit costs. The increase in other financial information appearing elsewhereoperating expenses in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm,2011 compared to the same period of 2010 was principally due to expenses associated with nuclear refueling outages at OE’s leased Perry Unit 1 and Beaver Valley Unit 2 that were absent in 2010. Decreased pensions and OPEB mark-to-market adjustment charges are the result of lower net actuarial losses in 2011 compared to 2010. The amortization of regulatory assets decreased primarily due to higher deferred residential generation credits in 2011. General taxes increased as a result of higher property taxes.
Interest Rate Risk
OE’s exposure to fluctuations in market interest rates is reduced since all of its debt has expressed an unqualified opinionfixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for OE’s investment portfolio and debt obligations.


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Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income $31
 $36
 $42
 $37
 $13
 $138
 $297
 $318
Average interest rate 8.7% 8.8% 8.8% 8.9% 8.9% 4.4% 6.8%  
Liabilities:                
Long-term Debt:                
Fixed rate       $150
 $250
 $757
 $1,157
 $1,434
Average interest rate       5.5% 6.4% 7.3% 6.9%  
Equity Price Risk
NDT funds have been established to satisfy nuclear decommissioning obligations. Included in OE’s NDT are fixed income and short-term investments carried at market values of approximately $134 million and $1 million, respectively, as of December 31, 2011, excluding $2 million of net receivables, payables and accrued income. OE recognizes in earnings the unrealized losses on available-for-sale securities held in its NDT as OTTI. A decline in the value of OE's NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During 2011, approximately $4 million was contributed to OE's NDT to comply with requirements under certain sale-leaseback transactions in which OE continues as a lessee.
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. OE evaluates the credit standing of a prospective counterparty based on the Company’s 2009 consolidatedprospective counterparty's financial statements.condition. OE may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. OE monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.


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THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
FirstEnergy Corp.’s internal auditors, who are responsibleMANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI provides regulated electric distribution services in an area of 1,600 square miles in northeastern Ohio. The area it serves has a population of approximately 1.7 million. CEI also procures generation services for those customers electing to retain them as their power supplier.
For additional information with respect to CEI, please see the Audit Committeeinformation contained in FirstEnergy’s Management’s Discussion and Analysis of FirstEnergy’s BoardFinancial Condition and Results of Directors, reviewOperations under the resultsfollowing subheadings: Strategy and performance of the Company for adequacy, effectivenessOutlook, Risks and reliability of accountingChallenges, Capital Resources and reporting systems, as well as managerialLiquidity, Contractual Obligations, Off-Balance Sheet Arrangements, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and operating controls.New Accounting Standards and Interpretations.
FirstEnergy’s Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm's report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm's independence. The Committee also reviews management’s programs to monitor complianceOn January 25, 2012, CEI filed a Form 15 with the Company’s policies on business ethicsSEC to deregister its securities and risk management. The Committee establishes proceduressuspend its obligation to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held nine meetings in 2009.
Management's Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) offile periodic reports under the Securities Exchange Act of 1934. Using1934, as amended, except that the criteria set forthregistrant has filed this Annual Report on Form 10-K for the year ended December 31, 2011. This Annual Report on Form 10-K will be the last filing made by CEI with the CommitteeSEC under the Exchange Act.
Results of Sponsoring OrganizationsOperations
Earnings available to parent decreased by $5 million in 2011 compared to 2010. The decrease in earnings was primarily due to decreased revenues, partially offset by lower purchased power costs and amortization of regulatory assets.
Revenues
Revenues decreased $345 million, or 28%, in 2011 compared to 2010 due to lower retail generation and distribution revenues.
Distribution revenues decreased $78 million in 2011 compared to 2010 due to lower average unit prices in all customer classes offset by increased MWH deliveries to the industrial sector. The lower average unit prices were the result of the Treadway Commissionabsence of transition charges in Internal Control – Integrated Framework2011. Lower residential and commercial deliveries resulted from decreased weather-related usage in 2011. In the industrial sector, MWH deliveries increased primarily as a result of recovering economic conditions in CEI's service territory.
Changes in distribution MWH deliveries and revenues in 2011 compared to 2010 are summarized in the following tables:
Distribution MWH DeliveriesIncrease (Decrease)
Residential(0.3)%
Commercial(0.4)%
Industrial1.4 %
Net Increase in Distribution Deliveries0.2 %
Distribution Revenues Decrease
  (In millions)
Residential $(12)
Commercial (7)
Industrial (59)
Decrease in Distribution Revenues $(78)
Retail generation revenues decreased $265 million in 2011 as compared to 2010 primarily due to lower MWH sales to all customer classes that resulted from increased customer shopping and lower average unit prices for the commercial and residential customer classes. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. CEI defers the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings. Lower MWH sales were the result of increased shopping by residential, commercial and industrial customers of 15%, 8% and 36%, respectively, in 2011 compared to 2010. Lower average unit prices in the residential customer class were primarily due to the lower auction price in 2011.


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Changes in retail generation sales and revenues in 2011 compared to 2010 are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(38.8)%
Commercial(37.6)%
Industrial(71.3)%
Decrease in Retail Generation Sales(52.2)%
Retail Generation Revenues Decrease
  (In millions)
Residential $(88)
Commercial (77)
Industrial (100)
Decrease in Retail Generation Revenues $(265)
Operating Expenses
Total operating expenses decreased $336 million in 2011 compared to 2010. The following table presents changes from the prior year by expense category:
Operating Expenses - Changes 
Increase
(Decrease)
  (In millions)
Purchased power costs $(254)
Other operating costs 15
Pensions and OPEB mark-to-market adjustment 8
Provision for depreciation 1
Amortization of regulatory assets, net (117)
General taxes 11
Net Decrease in Operating Expenses $(336)
Purchased power costs decreased in 2011 primarily due to lower MWH purchases resulting from reduced sales requirements as a result of increased customer shopping. Other operating expenses increased due to 2011 inventory valuation adjustments. Increased pensions and OPEB mark-to-market adjustment changes were due to higher net actuarial losses in 2011 as compared to 2010. Amortization of regulatory assets decreased primarily due to the completion of transition cost recovery at the end of 2010 and higher deferred purchased power costs in 2011, partially offset by increased recovery of deferred distribution costs and the absence in 2011 of renewable energy credit expenses that were deferred in 2010. General taxes increased due to increased property taxes as compared to 2010.
Interest Rate Risk
CEI's exposure to fluctuations in market interest rates is reduced since all of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for CEI’s investment portfolio and debt obligations.


112


Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income $66
 $75
 $80
 $50
 $16
   $287
 $315
Average interest rate 7.7% 7.7% 7.7% 7.7% 8.0%   7.7%  
Liabilities:                
Long-term Debt:                
Fixed rate   $325
 $26
 $24
 $6
 $1,450
 $1,831
 $2,162
Average interest rate   5.8% 7.7% 7.7% 7.7% 6.8% 6.7%  
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. CEI evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. CEI may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. CEI monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management conductedgroup oversees credit risk.


113


THE TOLEDO EDISON COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
TE is a wholly owned electric utility subsidiary of FirstEnergy. TE provides regulated electric distribution services in an evaluationarea of 2,300 square miles in northwestern Ohio. The area it serves has a population of approximately 0.7 million. TE also provides generation services to those customers electing to retain them as their power supplier.
For additional information with respect to TE, please see the effectivenessinformation contained in FirstEnergy’s Management’s Discussion and Analysis of the Company’s internal control over financial reportingFinancial Condition and Results of Operations under the supervision of the chief executive officerfollowing subheadings, which information is incorporated by reference herein: Strategy and the chief financial officer. Based on that evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2009.Outlook, Risks and Challenges, Capital Resources and Liquidity, Contractual Obligations, Off-Balance Sheet Arrangements, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
This annual report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting.

133
MANAGEMENT REPORTS
Management's Responsibility for Financial Statements
The consolidated financial statements of Ohio Edison Company (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2009 consolidated financial statements.
FirstEnergy Corp.’s internal auditors, who are responsible to the Audit Committee of FirstEnergy’s Board of Directors, review the results and performance of the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.
FirstEnergy’s Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm's report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm's independence. The Committee also reviews management’s programs to monitor complianceOn January 25, 2012, TE filed a Form 15 with the Company’s policies on business ethicsSEC to deregister its securities and risk management. The Committee establishes proceduressuspend its obligation to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held nine meetings in 2009.
Management's Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) offile periodic reports under the Securities Exchange Act of 1934. Using1934, as amended, except that the criteria set forthregistrant has filed this Annual Report on Form 10-K for the year ended December 31, 2011. This Annual Report on Form 10-K will be the last filing made by TE with the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework, management conducted an evaluation of the effectiveness of the Company’s internal control over financial reportingSEC under the supervisionExchange Act.
Results of Operations
Earnings available to parent decreased by $2 million in 2011 compared to 2010. The decrease was primarily from lower revenues and higher other operating expenses, partially offset by lower purchased power costs from affiliates.
Revenues
Revenues decreased $40 million, or 8%, in 2011 compared to 2010, primarily due to lower retail generation sales, partially offset by an increase in distribution revenues.
Distribution revenues increased $28 million in 2011 compared to 2010, primarily due to higher MWH deliveries to residential and industrial customers and higher unit prices to all customer classes related to increased energy efficiency rider rates, partially offset by lower MWH deliveries to commercial customers. Higher MWH deliveries to residential customers reflected increased load growth slightly offset by lower weather-related usage that also drove lower deliveries to commercial customers. In the chief executive officerindustrial sector, MWH deliveries increased primarily as a result of recovering economic conditions in TE's service territory.
Changes in distribution MWH deliveries and revenues in 2011 compared to 2010 are summarized in the chief financial officer. Based on that evaluation, management concluded thatfollowing tables:
Distribution MWH DeliveriesIncrease (Decrease)
Residential0.3 %
Commercial(1.9)%
Industrial2.4 %
Net Increase in Distribution Deliveries1.0 %
Distribution Revenues Increase
  (In millions)
Residential $11
Commercial 9
Industrial 8
Increase in Distribution Revenues $28
Retail generation revenues decreased $79 million in 2011 compared to 2010, primarily due to lower MWH sales from increased customer shopping and lower unit prices to all customer classes. The increases in shopping for residential, commercial and industrial customers were 13%, 9%, and 4%, respectively, in 2011 compared with 2010. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. TE defers the Company’s internal control over financial reportingdifference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings.


114


Decreases in retail generation MWH sales and revenues in 2011 compared to 2010 are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(27.9)%
Commercial(39.7)%
Industrial(10.1)%
Decrease in Retail Generation Sales(20.5)%
Retail Generation Revenues Decrease
  (In millions)
Residential $(28)
Commercial (21)
Industrial (30)
Decrease in Retail Generation Revenues $(79)
Wholesale revenues increased $12 million in 2011 compared to 2010, primarily due to higher revenues from sales to NGC from TE’s leasehold interest in Beaver Valley Unit 2.
Operating Expenses
Total operating expenses decreased $37 million in 2011 compared to 2010. The following table presents changes from the prior year by expense category:
Operating Expenses - Changes Increase (Decrease)
  (In millions)
Purchased power costs $(76)
Other operating expenses 31
Pensions and OPEB mark-to-market adjustment 6
General taxes 2
Net Decrease in Operating Expenses $(37)
Purchased power costs decreased in 2011 compared to 2010, due to lower MWH purchases resulting from reduced generation sales requirements in 2011 coupled with lower unit costs. The increase in other operating costs in 2011 was effectiveprimarily due to expenses associated with the 2011 nuclear refueling outage at the leased Beaver Valley Unit 2 and an Ohio Supreme Court decision rendered in the second quarter of 2011 favoring a large industrial customer, both of which were absent in 2010. Increased pensions and OPEB mark-to-market adjustment charges were due to higher net actuarial losses in 2011 as compared to 2010.
Other Expense
Other expense decreased slightly in 2011 compared to 2010, due to a decrease in miscellaneous expense partially offset by lower investment income. The change in miscellaneous expense was due to decreased expenses associated with the accounts receivable securitization with Centerior Funding Corp., which was terminated in 2011 Investment income decreased principally due to lower NDT investment income.
Interest Rate Risk
TE's exposure to fluctuations in market interest rates is reduced since all of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for TE’s investment portfolio and debt obligations.


115


Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income   $25
 $26
 $24
 $6
 $53
 $134
 $145
Average interest rate   7.7% 7.7% 7.7% 7.7% 4.6% 6.4%  
Liabilities:                
Long-term Debt:                
Fixed rate           $600
 $600
 $741
Average interest rate           6.7% 6.7%  
Equity Price Risk
NDT funds have been established to satisfy nuclear decommissioning obligations. Included in TE’s NDT are fixed income, equities and short-term investments carried at market values of approximately $53 million, $27 million and $3 million, respectively, as of December 31, 2009.2011. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $3 million reduction in fair value as of December 31, 2011. TE recognizes in earnings the unrealized losses on available-for-sale securities held in their NDT as OTTI. A decline in the value of TE’s NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During 2011, approximately $1 million was contributed to TE's NDT to comply with requirements under certain sale-leaseback transactions in which TE continues as a lessee.
Credit Risk
This annual report does not includeCredit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. TE evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. TE may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. TE monitors the financial conditions of existing counterparties on an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting.ongoing basis. An independent risk management group oversees credit risk.


116
134

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 in 3,200 square miles of northern, western and east central New Jersey. The area it serves has a population of approximately 2.7 million. JCP&L also has an ownership interest in a hydroelectric generating facility. In addition, JCP&L also procures generation services for franchise customers electing to retain them as their power supplier. JCP&L procures electric supply to serve its BGS customers through a statewide auction process approved by the NJBPU.
MANAGEMENT REPORTSFor 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: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Contractual Obligations, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
Results of Operations
Management's ResponsibilityNet income decreased by $39 million in 2011 compared to 2010. The decrease was primarily due to lower revenues, partially offset by reductions in purchased power costs and amortization of regulatory assets.
Revenues
Revenues decreased by $532 million, or 18%, in 2011 compared to 2010. The decrease in revenues was due to lower distribution, retail generation and wholesale generation revenues, partially offset by an increase in other revenues.
Distribution revenues decreased by $187 million in 2011, compared to 2010, primarily due to an NJBPU-approved rate adjustment that became effective March 1, 2011 for Financial Statementsall customer classes, and lower MWH deliveries. The lower MWH deliveries to residential customers were influenced by decreased weather-related usage in 2011. Lower distribution deliveries to commercial and industrial customers reflected the impact of economic conditions in JCP&L's service territory.
The consolidated financial statements of The Cleveland Electric Illuminating Company (Company) were prepared by management, who takes responsibility for their integrityDecreases in distribution MWH deliveries and objectivity. The statements were preparedrevenues in conformity with accounting principles generally accepted2011 compared to 2010 are summarized in the United Statesfollowing tables:
Distribution MWH DeliveriesDecrease
Residential(3.0)%
Commercial(2.9)%
Industrial(3.0)%
Decrease in Distribution Deliveries(2.9)%
Distribution Revenues Decrease
  (In millions)
Residential $(90)
Commercial (79)
Industrial (18)
Decrease in Distribution Revenues $(187)

Retail generation revenues decreased by $301 million due to lower generation MWH sales in all customer classes primarily due to an increase in customer shopping. The increases in shopping for residential, commercial and industrial customers were 10%, 9% and 5%, respectively, in 2011 compared with 2010. Retail generation obligations are attributable to non-shopping customers and are consistent with othersatisfied by generation procured through full-requirements auctions. JCP&L defers the difference between retail generation revenues and purchased power costs, resulting in no material effect to earnings.


117


Decreases in retail generation MWH sales and revenues in 2011, compared to 2010, are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(13.0)%
Commercial(23.0)%
Industrial(29.0)%
Decrease in Retail Generation Sales(16.3)%
Retail Generation Revenues Decrease
  (In millions)
Residential $(181)
Commercial (108)
Industrial (12)
Decrease in Retail Generation Revenues $(301)

Wholesale generation revenues decreased by $54 million in 2011, compared to 2010, due to a decrease in PJM spot market energy sales.
Other revenues increased by $10 million in 2011, compared to 2010, primarily due to increases in PJM network transmission revenues and transition bond revenues from increased rates.
Operating Expenses
Total operating expenses decreased by $461 million in 2011 compared to 2010. The following table presents changes from the prior year by expense category:
Operating Expenses - Changes Increase (Decrease)
  (In millions)
Purchased power costs $(354)
Other operating expenses 48
Pensions and OPEB mark-to-market adjustment 34
Provision for depreciation 22
Amortization of regulatory assets, net (213)
General taxes 2
Net Decrease in Operating Expenses $(461)

Purchased power costs decreased by $354 million in 2011 due to lower requirements from reduced retail generation sales. Other operating expenses increased by $48 million in 2011 principally from storm restoration maintenance costs. Increased pensions and OPEB mark-to-market adjustment changes were due to higher net actuarial losses in 2011 as compared to 2010. Amortization of regulatory assets, net, decreased by $213 million due to reduced cost recovery under the NJBPU-approved NUG tariffs that became effective March 1, 2011 and higher deferred storm restoration costs, partially offset by a charge for nonrecoverable NUG costs.
Market Risk Information
JCP&L uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.
Commodity Price Risk
JCP&L is exposed to financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2009 consolidated financial statements.
FirstEnergy Corp.’s internal auditors, who are responsible to the Auditrisks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas and energy transmission. FirstEnergy's Risk Policy Committee of FirstEnergy’s Board of Directors, review the results and performance of the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.
FirstEnergy’s Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm's report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm's independence. The Committee also reviews management’s programs to monitor compliance with the Company’s policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held nine meetings in 2009.
Management's Report on Internal Control Over Financial Reporting
Management is responsible for establishingpromoting the effective design and maintaining adequate internal control overimplementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. JCP&L uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.
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, JCP&L relies on model-based information. The model provides estimates of future


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regional prices for electricity and an estimate of related price volatility. JCP&L uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making (see Note 9, Fair Value Measurements of the Combined Notes to the Consolidated Financial Statements). Sources of information for the valuation of commodity derivative contract assets and liabilities as of December 31, 2011, are summarized by year in the following table:
Source of Information-
Fair Value by Contract Year
 2012 2013 2014 2015 2016 Thereafter Total
  (In millions)
Prices actively quoted(1)
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Other external sources(2)
 (52) (43) (36) (14) —
 —
 (145)
Prices based on models —
 —
 —
 —
 1
 1
 2
Total(3)
 $(52) $(43) $(36) $(14) $1
 $1
 $(143)
(1)
Represents exchange traded New York Mercantile Exchange futures and options.
(2)
Primarily represents contracts based on broker and IntercontinentalExchange quotes.
(3)
Includes $(143) million in non-hedge commodity derivative contracts that are related to NUG contracts. NUG contracts are subject to regulatory accounting and do not materially impact earnings.
JCP&L performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. Based on derivative contracts held as of December 31, 2011, an adverse 10% change in commodity prices would not have a material effect on JCP&L’s net income for the next 12 months.
Interest Rate Risk
JCP&L’s exposure to fluctuations in market interest rates is reduced since all of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for JCP&L’s investment portfolio and debt obligations.
Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income           $363
 $363
 $363
Average interest rate           5.2% 5.2%  
Liabilities:                
Long-term Debt:                
Fixed rate $34
 $36
 $38
 $41
 $343
 $1,285
 $1,777
 $2,080
Average interest rate 5.7% 5.7% 5.9% 6.0% 5.7% 6.2% 6.1%  
Equity Price Risk
NDT funds have been established to satisfy nuclear decommissioning obligations. Included in JCP&L’s NDT are fixed income, equities and short-term investments carried at market values of approximately $147 million, $30 million and $14 million, respectively, as of December 31, 2011, excluding $2 million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $3 million reduction in fair value as of December 31, 2011. JCP&L's NDT is 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. A decline in the value of JCP&L's NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During 2011, approximately $1 million was contributed to JCP&L's NDT to comply with regulatory requirements.
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. JCP&L evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. JCP&L may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. JCP&L monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.


119


METROPOLITAN EDISON COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
Met-Ed is a wholly owned electric utility subsidiary of FirstEnergy. Met-Ed provides regulated electric transmission and distribution services in Rule 13a-15(f)3,300 square miles of eastern and south central Pennsylvania. The area it serves has a population of approximately 1.2 million. Met-Ed also procures generation service for those franchise customers who have elected to retain them as their power supplier. Met-Ed procures power under its DSP, in which full requirements products (energy, capacity, ancillary services, and applicable transmission services) are procured through descending clock auctions.
For additional information with respect to Met-Ed, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Contractual Obligations, Off-Balance Sheet Arrangements, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
On January 25, 2012, Met-Ed filed a Form 15 with the SEC to deregister its securities and suspend its obligation to file periodic reports under the Securities Exchange Act of 1934. Using1934, as amended, except that the criteria set forthregistrant has filed this Annual Report on Form 10-K for the year ended December 31, 2011. This Annual Report on Form 10-K will be the last filing made by Met-Ed with the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework, management conducted an evaluation of the effectiveness of the Company’s internal control over financial reportingSEC under the supervisionExchange Act.
Results of Operations
Net income increased by $8 million in 2011 compared to 2010. The increase was primarily due to decreased purchased power costs, other operating expenses and amortization of net regulatory assets partially offset by decreased revenues.
Revenues
Revenue decreased $606 million, or 33%, in 2011 compared to 2010, reflecting lower distribution, retail generation, wholesale generation and transmission revenues.
Distribution revenues decreased $336 million in 2011 compared to 2010, primarily due to lower rates resulting from the chief executive officerDSP that began in 2011 that eliminated the transmission component from the distribution rates. The lower MWH deliveries to residential and commercial customers were influenced by decreased weather-related usage in 2011. In the industrial sector, MWH deliveries increased primarily as a result of recovering economic conditions in Met-Ed's service territory.
Changes in distribution MWH deliveries and revenues in 2011 compared to 2010 are summarized in the following tables:
Distribution MWH DeliveriesIncrease (Decrease)
Residential(1.4)%
Commercial(2.0)%
Industrial2.2 %
Net Decrease in Distribution Deliveries(0.2)%
Distribution Revenues Decrease
  (In millions)
Residential $(133)
Commercial (90)
Industrial (113)
Decrease in Distribution Revenues $(336)
In 2011, retail generation revenues decreased $52 million due to lower MWH sales to all customer classes resulting from increased customer shopping. The impact of increased customer shopping is partially offset by higher generation rates that reflect the inclusion of transmission services under the DSP, effective January 1, 2011, for all customer classes. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. In 2011, Met-Ed began deferring the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings.


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Changes in retail generation MWH sales and revenues in 2011 compared to 2010 are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(3.8)%
Commercial(49.1)%
Industrial(91.8)%
Net Decrease in Retail Generation Sales(45.7)%
Retail Generation Revenues Increase (Decrease)
  (In millions)
Residential $166
Commercial (24)
Industrial (194)
Net Decrease in Retail Generation Revenues $(52)
Wholesale revenues decreased $210 million in 2011 compared to 2010, primarily reflecting lower RPM revenues for Met-Ed in the PJM market.
Transmission revenues decreased $9 million in 2011 compared to 2010 primarily due to the termination of Met-Ed’s TSC rates effective January 1, 2011. Met-Ed deferred the difference between transmission revenues and transmission costs incurred, resulting in no material effect to earnings in the period.
Operating Expenses
Total operating expenses decreased $608 million in 2011 compared to 2010. The following table presents changes from the prior year by expense category:
Operating Expenses - Changes Increase (Decrease)
  (In millions)
Purchased power costs $(328)
Other operating costs (230)
Pensions and OPEB mark-to-market adjustment 26
Provision for depreciation 5
Amortization of regulatory assets, net (68)
General taxes (13)
Net Decrease in Operating Expenses $(608)
Purchased power costs decreased $328 million in 2011 compared to 2010 due to a decrease in MWH purchased to source generation sales requirements, partially offset by higher unit costs. Decreased power purchased from affiliates reflects the increase in customer shopping described above and the chief financial officer. Based ontermination of Met-Ed's partial requirements PSA with FES at the end of 2010. Other operating costs decreased $230 million in 2011 compared to 2010 due to lower transmission congestion and transmission loss expenses that evaluation,are now included in the cost of purchased power (see reference to deferral accounting above), partially offset by increased costs for energy efficiency programs. Increased pensions and OPEB mark-to-market adjustment changes were due to higher net actuarial losses in 2011 as compared to 2010. The amortization of regulatory assets decreased $68 million in 2011 compared to 2010 primarily due to the termination of transmission and transition tariff riders at the end of 2010. General taxes decreased by $13 million in 2011 primarily due to lower gross receipts taxes.
Other Expense
Interest income decreased by $3 million in 2011 compared to 2010 primarily due to reduced CTC stranded asset balances.
Market Risk Information
Met-Ed uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, concluded thatprovides general oversight for risk management activities throughout the Company’s internal control over financial reporting was effective as of December 31, 2009.
This annual report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting.company.


121
135

Commodity Price Risk
MANAGEMENT REPORTS
Management's ResponsibilityMet-Ed is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for Financial Statements
The consolidated financial statements of The Toledo Edison Company (Company) were prepared by management, who takes responsibility for their integrityelectricity, natural gas and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2009 consolidated financial statements.
FirstEnergy Corp.’s internal auditors, who are responsible to the Auditenergy transmission. FirstEnergy's Risk Policy Committee of FirstEnergy’s Board of Directors, review the results and performance of the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.
FirstEnergy’s Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm's report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm's independence. The Committee also reviews management’s programs to monitor compliance with the Company’s policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held nine meetings in 2009.
Management's Report on Internal Control Over Financial Reporting
Management is responsible for establishingpromoting the effective design and maintaining adequate internal control overimplementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. Met-Ed uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.
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, Met-Ed relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Met-Ed uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making (see Note 9, Fair Value Measurements of the Combined Notes to the Consolidated Financial Statements). Sources of information for the valuation of commodity derivative contract assets and liabilities as of December 31, 2011, are summarized by year in the following table:
Source of Information-
Fair Value by Contract Year
 2012 2013 2014 2015 2016 Thereafter Total
  (In millions)
Prices actively quoted(1)
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Other external sources(2)
 (62) (7) (6) (5) —
 —
 (80)
Prices based on models —
 —
 —
 —
 8
 42
 50
Total(3)
 $(62) $(7) $(6) $(5) $8
 $42
 $(30)
(1)
Represents exchange traded New York Mercantile Exchange futures and options.
(2)
Primarily represents contracts based on broker and IntercontinentalExchange quotes.
(3)
Includes $(30) million in non-hedge commodity derivative contracts that are related to NUG contracts. NUG contracts are subject to regulatory accounting and do not materially impact earnings.
Met-Ed performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. Based on derivative contracts held as of December 31, 2011, an adverse 10% change in commodity prices would not have a material effect on Met-Ed’s net income for the next 12 months.
Interest Rate Risk
Met-Ed’s exposure to fluctuations in market interest rates is reduced since a significant portion of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for Met-Ed’s investment portfolio and debt obligations.
Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income           $234
 $234
 $234
Average interest rate           3.3% 3.3%  
Liabilities:                
Long-term Debt:                
Fixed rate   $150
 $250
     $300
 $700
 $796
Average interest rate   5.0% 4.9%     7.7% 6.1%  
Variable rate           $29
 $29
 $29
Average interest rate           0.1% 0.1%  
Equity Price Risk
NDT funds have been established to satisfy nuclear decommissioning obligations. Included in Met-Ed’s NDT are fixed income, equities and short-term investments carried at market values of approximately $234 million, $51 million and $23 million, respectively, as of December 31, 2011, excluding $2 million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $5 million reduction in fair value as of December 31, 2011. Met-Ed's NDT is 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. A decline


122


in the value of Met-Ed's NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements.
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. Met-Ed evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. Met-Ed may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. Met-Ed monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.


123


PENNSYLVANIA ELECTRIC COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec provides regulated electric transmission and distribution services in Rule 13a-15(f)17,600 square miles of western, northern and south central Pennsylvania. The area it serves has a population of approximately 1.3 million. Penelec, as lessee of the property of its subsidiary, The Waverly Electric Light & Power Company, serves customers in the Waverly, New York vicinity. Penelec also procures generation service for those franchise customers who have elected to retain them as their power supplier. Penelec procures power under its DSP, in which full requirements products (energy, capacity, ancillary services and applicable transmission services) are procured through descending clock auctions.
For additional information with respect to Penelec, 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: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Contractual Obligations, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
On January 25, 2012, Penelec filed a Form 15 with the SEC to deregister its securities and suspend its obligation to file periodic reports under the Securities Exchange Act of 1934. Using1934, as amended, except that the criteria set forthregistrant has filed this Annual Report on Form 10-K for the year ended December 31, 2011. This Annual Report on Form 10-K will be the last filing made by Penelec with the CommitteeSEC under the Exchange Act.
Results of Sponsoring OrganizationsOperations
Net income was unchanged in 2011, compared to 2010, due to lower purchased power costs, other operating expenses and income taxes, partially offset by lower revenues and higher amortization of regulatory assets.
Revenues
Revenues decreased by $459 million, or 30%, in 2011 compared to 2010. The decrease in revenue was primarily due to lower distribution, retail generation, wholesale generation and transmission revenues.
Distribution revenues decreased by $93 million in 2011, compared to 2010, primarily due to lower rates resulting from the DSP, which eliminated the transmission component from the distribution rate beginning in 2011, partially offset by a PPUC-approved rate adjustment for NUG costs. Lower MWH deliveries to residential and commercial customers reflected decreased weather-related usage compared to 2010. Higher MWH deliveries to industrial customers were primarily due to recovering economic conditions in Penelec’s service territory, compared to 2010.
Changes in distribution MWH deliveries and revenues in 2011, compared to 2010, are summarized in the following tables:
Distribution MWH Deliveries
Increase
(Decrease)
Residential(2.2)%
Commercial(3.7)%
Industrial4.5 %
Net Decrease in Distribution Deliveries0.1 %
Distribution Revenues Decrease
  (In millions)
Residential $(35)
Commercial (31)
Industrial (27)
Decrease in Distribution Revenues $(93)

Retail generation revenues decreased by $218 million in 2011, compared to 2010, due to lower MWH sales in all customer classes resulting from increased customer shopping. The impact of customer shopping was partially offset by higher generation rates that reflect the inclusion of transmission services under the DSP, effective January 1, 2011, for all customer classes. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. In 2011, Penelec began deferring the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings.


124


Changes in retail generation MWH sales and revenues in 2011, compared to 2010, are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(8.5)%
Commercial(53.6)%
Industrial(92.5)%
Decrease in Retail Generation Sales(53.1)%
Retail Generation Revenues 
Increase
(Decrease)
  (In millions)
Residential $87
Commercial (78)
Industrial (227)
Net Decrease in Retail Generation Revenues $(218)

Wholesale generation revenues decreased by $205 million in 2011, compared to 2010, reflecting lower RPM revenues for Penelec in the PJM market.
Transmission revenues decreased by $7 million in 2011, compared to 2010, primarily due to the termination of Penelec’s TSC rates effective January 1, 2011. Penelec deferred the difference between transmission revenues and transmission costs incurred, resulting in no material effect to earnings for the period.
Operating Expenses

Total operating expenses decreased by $446 million in 2011 as compared to 2010. The following table presents changes from the prior year by expense category:
Operating Expenses - Changes Increase (Decrease)
  (In millions)
Purchased power costs (467)
Other operating costs (99)
Pensions and OPEB mark-to-market adjustment 33
Provision for depreciation (3)
Amortization of regulatory assets, net 97
General taxes (7)
Net Decrease in Operating Expenses $(446)

Purchased power costs decreased by $467 million in 2011, compared to 2010, due to a decrease in MWH purchased to source generation sales requirements. Decreased power purchased from affiliates resulted from reduced requirements due to the increase in customer shopping described above and the termination of Penelec's partial requirements PSA with FES at the end of 2010. Other operating costs decreased by $99 million in 2011 due to lower transmission congestion and transmission loss expenses that are now included in the cost of purchased power (see reference to deferral accounting above). Increased pensions and OPEB mark-to-market adjustment charges were due to higher net actuarial losses in 2011 as compared to 2010. The amortization of regulatory assets increased by $97 million in 2011 primarily due to reduced NUG deferrals as a result of the Treadway CommissionPPUC-approved increase in Internal Control – Integrated Framework, management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting under the supervision of the chief executive officer and the chief financial officer. Based on that evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2009.Penelec’s NUG cost recovery rider in January 2011.
Other Expenses
This annual report does not include an attestation reportOther expenses decreased by $3 million in 2011, compared to 2010, due to lower income from jobbing and contracting work and lower capitalized interest.
Market Risk Information
Penelec uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the Company’s registered public accounting firm regarding internal control over financial reporting.company.



125
136

Commodity Price Risk
MANAGEMENT REPORTS
Management's ResponsibilityPenelec is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for Financial Statements
The consolidated financial statements of Jersey Central Power & Light Company (Company) were prepared by management, who takes responsibility for their integrityelectricity, natural gas and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2009 consolidated financial statements.
FirstEnergy Corp.’s internal auditors, who are responsible to the Auditenergy transmission. FirstEnergy's Risk Policy Committee of FirstEnergy’s Board of Directors, review the results and performance of the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.
FirstEnergy’s Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm's report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm's independence. The Committee also reviews management’s programs to monitor compliance with the Company’s policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held nine meetings in 2009.
Management's Report on Internal Control Over Financial Reporting
Management is responsible for establishingpromoting the effective design and maintaining adequate internal control overimplementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. Penelec uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.
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, Penelec relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Penelec uses these results to develop estimates of fair value for financial reporting as defined in Rule 13a-15(f)purposes and for internal management decision making (see Note 9, Fair Value Measurements of the Securities Exchange ActCombined Notes to the Consolidated Financial Statements). Sources of 1934. Usinginformation for the criteria set forthvaluation of commodity derivative contract assets and liabilities as of December 31, 2011, are summarized by year in the Committeefollowing table:
Source of Information-
Fair Value by Contract Year
 2012 2013 2014 2015 2016 Thereafter Total
  (In millions)
Prices actively quoted(1)
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Other external sources(2)
 (85) (12) (10) (11) —
 —
 (118)
Prices based on models —
 —
 —
 —
 1
 (3) (2)
Total(3)
 $(85) $(12) $(10) $(11) $1
 $(3) $(120)
(1)
Represents exchange traded New York Mercantile Exchange futures and options.
(2)
Primarily represents contracts based on broker and IntercontinentalExchange quotes.
(3)
Includes $(120) million in non-hedge commodity derivative contracts that are related to NUG contracts. NUG contracts are subject to regulatory accounting and do not materially impact earnings.
Penelec performs sensitivity analyses to estimate its exposure to the market risk of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework, management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting under the supervision of the chief executive officer and the chief financial officer.its commodity positions. Based on that evaluation, management concluded that the Company’s internal control over financial reporting was effectivederivative contracts held as of December 31, 20092011.
This annual report does not include, an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting.

137
MANAGEMENT REPORTS
Management's Responsibility for Financial Statements
The consolidated financial statements of Metropolitan Edison Company (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were preparedadverse 10% change in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2009 consolidated financial statements.
FirstEnergy Corp.’s internal auditors, who are responsible to the Audit Committee of FirstEnergy’s Board of Directors, review the results and performance of the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.
FirstEnergy’s Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm's report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm's independence. The Committee also reviews management’s programs to monitor compliance with the Company’s policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held nine meetings in 2009.
Management's Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework, management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting under the supervision of the chief executive officer and the chief financial officer. Based on that evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2009.
This annual report doescommodity prices would not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting.

138
MANAGEMENT REPORTS
Management's Responsibility for Financial Statements
The consolidated financial statements of Pennsylvania Electric Company (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2009 consolidated financial statements.
FirstEnergy Corp.’s internal auditors, who are responsible to the Audit Committee of FirstEnergy’s Board of Directors, review the results and performance of the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.
FirstEnergy’s Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm's report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm's independence. The Committee also reviews management’s programs to monitor compliance with the Company’s policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held nine meetings in 2009.
Management's Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework, management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting under the supervision of the chief executive officer and the chief financial officer. Based on that evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2009.
This annual report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting.

139
Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors of FirstEnergy Corp.:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, common stockholders' equity, and cash flows present fairly, in all material respects, the financial position of FirstEnergy Corp. and its subsidiaries at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on Penelec’s net income for the financial statements.next 12 months.
Interest Rate Risk
BecausePenelec’s exposure to fluctuations in market interest rates is reduced since a significant portion of its inherent limitations, internal control over financial reporting may not preventdebt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for Penelec’s investment portfolio and debt obligations.
Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income           $195
 $195
 $195
Average interest rate           3.8% 3.8%  
Liabilities:                
Long-term Debt:                
Fixed rate     $150
     $925
 $1,075
 $1,206
Average interest rate     5.1%     5.9% 5.8%  
Variable rate           $45
 $45
 $45
Average interest rate           0.1% 0.1%  
Equity Price Risk
NDT funds have been established to satisfy nuclear decommissioning obligations. Included in Penelec’s NDT are fixed income, equities and short-term investments carried at market values of approximately $106 million, $26 million and $33 million, respectively, as of December 31, 2011, excluding $1 million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $3 million reduction in fair value as of December 31, 2011. Penelec's NDT is subject to regulatory accounting, with unrealized gains and losses recorded as regulatory assets or detect misstatements. Also, projectionsliabilities, since the difference between investments held in trust and the decommissioning liabilities will be recovered from or refunded to customers. A decline


126


in the value of any evaluation of effectiveness to future periods are subject toPenelec's NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements.
Credit Risk
Credit risk is defined as the risk that controlsa counterparty to a transaction will be unable to fulfill its contractual obligations. Penelec evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. Penelec may become inadequate becauseimpose specified collateral requirements and use standardized agreements that facilitate the netting of changes incash flows. Penelec monitors the financial conditions or that the degree of compliance with the policies or procedures may deteriorate.existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.


127


PricewaterhouseCoopers LLP
Cleveland, Ohio
February 18, 2010
ITEM 7A.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by ITEM 7A relating to market risk is set forth in ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.


128

140
Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of
Directors of FirstEnergy Solutions Corp.:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows present fairly, in all material respects, the financial position of FirstEnergy Solutions Corp. and its subsidiaries at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

PricewaterhouseCoopers LLP
Cleveland, Ohio
February 18, 2010
ITEM 8.		FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
141
Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of
Directors of Ohio Edison Company:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows present fairly, in all material respects, the financial position of Ohio Edison Company and its subsidiaries at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
PricewaterhouseCoopers LLP
Cleveland, Ohio
February 18, 2010
142
Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of Directors of
The Cleveland Electric Illuminating Company:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows present fairly, in all material respects, the financial position of The Cleveland Electric Illuminating Company and its subsidiaries at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
PricewaterhouseCoopers LLP
Cleveland, Ohio
February 18, 2010
143
Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of
Directors of The Toledo Edison Company:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows present fairly, in all material respects, the financial position of The Toledo Edison Company and its subsidiary at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
PricewaterhouseCoopers LLP
Cleveland, Ohio
February 18, 2010
144
Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of Directors of
Jersey Central Power & Light Company:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows present fairly, in all material respects, the financial position of Jersey Central Power & Light Company and its subsidiaries at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
PricewaterhouseCoopers LLP
Cleveland, Ohio
February 18, 2010
145
Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of
Directors of Metropolitan Edison Company:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows present fairly, in all material respects, the financial position of Metropolitan Edison Company and its subsidiaries at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
PricewaterhouseCoopers LLP
Cleveland, Ohio
February 18, 2010
146
Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of
Directors of Pennsylvania Electric Company:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows present fairly, in all material respects, the financial position of Pennsylvania Electric Company and its subsidiaries at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
PricewaterhouseCoopers LLP
Cleveland, Ohio
February 18, 2010
147

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2009  2008  2007 
  (In millions, except per share amounts) 
REVENUES:         
Electric utilities $11,139  $12,061  $11,305 
Unregulated businesses  1,828   1,566   1,497 
Total revenues*  12,967   13,627   12,802 
             
EXPENSES:            
Fuel  1,153   1,340   1,178 
Purchased power  4,730   4,291   3,836 
Other operating expenses  2,697   3,045   3,083 
Provision for depreciation  736   677   638 
Amortization of regulatory assets  1,155   1,053   1,019 
Deferral of regulatory assets  (136)  (316)  (524)
General taxes  753   778   754 
Total expenses  11,088   10,868   9,984 
             
OPERATING INCOME  1,879   2,759   2,818 
             
OTHER INCOME (EXPENSE):            
Investment income, net  204   59   120 
Interest expense  (978)  (754)  (775)
Capitalized interest  130   52   32 
Total other expense  (644)  (643)  (623)
             
INCOME BEFORE INCOME TAXES  1,235   2,116   2,195 
             
INCOME TAXES  245   777   883 
             
NET INCOME  990   1,339   1,312 
             
Noncontrolling interest income (loss)  (16)  (3)  3 
             
EARNINGS AVAILABLE TO FIRSTENERGY CORP. $1,006  $1,342  $1,309 
             
BASIC EARNINGS PER SHARE OF COMMON STOCK $3.31  $4.41  $4.27 
             
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING  304   304   306 
             
DILUTED EARNINGS PER SHARE OF COMMON STOCK $3.29  $4.38  $4.22 
             
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING  306   307   310 
  
* Includes $395 million, $432 million and $425 million of excise tax collections in 2009, 2008 and 2007, respectively.

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


148

FIRSTENERGY CORP. 
       
CONSOLIDATED BALANCE SHEETS 
       
As of December 31, 2009  2008 
 (In millions) 
ASSETS      
       
CURRENT ASSETS:      
Cash and cash equivalents $874  $545 
Receivables-        
Customers (less accumulated provisions of $33 million and        
$28 million, respectively, for uncollectible accounts)  1,244   1,304 
Other (less accumulated provisions of $7 million and        
$9 million, respectively, for uncollectible accounts)  153   167 
Materials and supplies, at average cost  647   605 
Prepaid taxes  248   283 
Other  154   149 
   3,320   3,053 
PROPERTY, PLANT AND EQUIPMENT:        
In service  27,826   26,482 
Less - Accumulated provision for depreciation  11,397   10,821 
   16,429   15,661 
Construction work in progress  2,735   2,062 
   19,164   17,723 
INVESTMENTS:        
Nuclear plant decommissioning trusts  1,859   1,708 
Investments in lease obligation bonds (Note 7)  543   598 
Other  621   711 
   3,023   3,017 
DEFERRED CHARGES AND OTHER ASSETS:        
Goodwill  5,575   5,575 
Regulatory assets  2,356   3,140 
Power purchase contract asset  200   434 
Other  666   579 
   8,797   9,728 
  $34,304  $33,521 
LIABILITIES AND CAPITALIZATION        
         
CURRENT LIABILITIES:        
Currently payable long-term debt $1,834  $2,476 
Short-term borrowings (Note 14)  1,181   2,397 
Accounts payable  829   794 
Accrued taxes  314   333 
Other  1,130   1,098 
   5,288   7,098 
CAPITALIZATION:        
Common stockholders’ equity-        
Common stock, $0.10 par value, authorized 375,000,000 shares-        
304,835,407 outstanding  31   31 
Other paid-in capital  5,448   5,473 
Accumulated other comprehensive loss  (1,415)  (1,380)
Retained earnings  4,495   4,159 
Total common stockholders' equity  8,559   8,283 
Noncontrolling interest  (2)  32 
Total equity  8,557   8,315 
Long-term debt and other long-term obligations (Note 12(C))
  11,908   9,100 
   20,465   17,415 
NONCURRENT LIABILITIES:        
Accumulated deferred income taxes  2,468   2,163 
Asset retirement obligations  1,425   1,335 
Deferred gain on sale and leaseback transaction  993   1,027 
Power purchase contract liability  643   766 
Retirement benefits  1,534   1,884 
Lease market valuation liability  262   308 
Other  1,226   1,525 
   8,551   9,008 
         
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Notes 7 and 15)     
  $34,304  $33,521 
         
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these 
financial statements.        

149

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY

              Accumulated  Unallocated 
     Common Stock  Other  Other     ESOP 
  Comprehensive Income  Number of Shares  Par Value  Paid-In Capital  Comprehensive Income (Loss)  Retained Earnings  Common Stock 
  (Dollars in millions) 
                      
Balance, January 1, 2007     319,205,517  $32  $6,466  $(259) $2,806  $(10)
Earnings available to FirstEnergy Corp. $1,309                   1,309     
Unrealized loss on derivative hedges, net                            
of $8 million of income tax benefits  (17)              (17)        
Unrealized gain on investments, net of                            
$31 million of income taxes  47               47         
Pension and other postretirement benefits, net                            
of $169 million of income taxes (Note 3)  179               179         
Comprehensive income $1,518                         
Stock options exercised              (40)            
Allocation of ESOP shares              26           10 
Restricted stock units              23             
Stock-based compensation              2             
Accounting for uncertainty in income taxes                            
cumulative effect adjustment                      (3)    
Repurchase of common stock      (14,370,110)  (1)  (968)            
Cash dividends declared on common stock                      (625)    
Balance, December 31, 2007      304,835,407   31   5,509   (50)  3,487   - 
Earnings available to FirstEnergy Corp. $1,342                   1,342     
Unrealized loss on derivative hedges, net                            
of $16 million of income tax benefits  (28)              (28)        
Change in unrealized gain on investments, net of                            
$86 million of income tax benefits  (146)              (146)        
Pension and other postretirement benefits, net                            
of $697 million of income tax benefits (Note 3)  (1,156)              (1,156)        
Comprehensive income $12                         
Stock options exercised              (36)            
Restricted stock units              (1)            
Stock-based compensation              1             
Cash dividends declared on common stock                      (670)    
Balance, December 31, 2008      304,835,407   31   5,473   (1,380)  4,159   - 
Earnings available to FirstEnergy Corp. $1,006                   1,006     
Unrealized gain on derivative hedges, net                            
of $24 million of income taxes  27               27         
Change in unrealized gain on investments, net of                            
$31 million of income tax benefits  (43)              (43)        
Pension and other postretirement benefits, net                            
of $34 million of income taxes (Note 3)  (19)              (19)        
Comprehensive income $971                         
Stock options exercised              (3)            
Restricted stock units              7             
Stock-based compensation              1             
Acquisition adjustment of non-controlling                            
interest (Note 8)              (30)            
Cash dividends declared on common stock                      (670)    
Balance, December 31, 2009      304,835,407  $31  $5,448  $(1,415) $4,495  $- 
 
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

150

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2009  2008  2007 
  (In millions) 
CASH FLOWS FROM OPERATING ACTIVITIES:         
Net income $990  $1,339  $1,312 
Adjustments to reconcile net income to net cash from operating activities-            
Provision for depreciation  736   677   638 
Amortization of regulatory assets  1,155   1,053   1,019 
Deferral of regulatory assets  (136)  (316)  (524)
Nuclear fuel and lease amortization  128   112   101 
Deferred purchased power and other costs  (338)  (226)  (350)
Deferred income taxes and investment tax credits, net  384   366   (9)
Investment impairment  62   123   26 
Deferred rents and lease market valuation liability  (52)  (95)  (99)
Stock based compensation  20   (64)  (39)
Accrued compensation and retirement benefits  22   (140)  (37)
Gain on asset sales  (27)  (72)  (30)
Electric service prepayment programs  (10)  (77)  (75)
Cash collateral, net  30   (31)  (68)
Gain on sales of investment securities held in trusts, net  (176)  (63)  (10)
Loss on debt redemption  146   -   - 
Commodity derivative transactions, net (Note 6)  229   5   6 
Pension trust contributions  (500)  -   (300)
Uncertain tax positions  (210)  (5)  19 
Decrease (increase) in operating assets-            
Receivables  75   (29)  (136)
Materials and supplies  (11)  (52)  79 
Prepayments and other current assets  (19)  (263)  10 
Increase (decrease) in operating liabilities-            
Accounts payable  50   10   51 
Accrued taxes  (103)  (39)  48 
Accrued interest  67   4   (8)
Other  (47)  7   75 
Net cash provided from operating activities  2,465   2,224   1,699 
             
CASH FLOWS FROM FINANCING ACTIVITIES:            
New Financing-            
Long-term debt  4,632   1,367   1,520 
Short-term borrowings, net  -   1,494   - 
Redemptions and Repayments-            
Common stock  -   -   (969)
Long-term debt  (2,610)  (1,034)  (1,070)
Short-term borrowings, net  (1,246)  -   (205)
Common stock dividend payments  (670)  (671)  (616)
Other  (57)  19   (7)
Net cash provided from (used for) financing activities  49   1,175   (1,347)
             
CASH FLOWS FROM INVESTING ACTIVITIES:            
Property additions  (2,203)  (2,888)  (1,633)
Proceeds from asset sales  21   72   42 
Proceeds from sale and leaseback transaction  -   -   1,329 
Sales of investment securities held in trusts  2,229   1,656   1,294 
Purchases of investment securities held in trusts  (2,306)  (1,749)  (1,397)
Cash investments (Note 5)  60   60   72 
Other  14   (134)  (20)
Net cash used for investing activities  (2,185)  (2,983)  (313)
             
Net increase in cash and cash equivalents  329   416   39 
Cash and cash equivalents at beginning of year  545   129   90 
Cash and cash equivalents at end of year $874  $545  $129 
             
SUPPLEMENTAL CASH FLOW INFORMATION:            
Cash Paid During the Year-            
Interest (net of amounts capitalized) $718  $667  $744 
Income taxes $173  $685  $710 
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

151

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2009  2008  2007 
  (In thousands) 
          
REVENUES:         
Electric sales to affiliates (Note 18) $2,825,959  $2,968,323  $2,901,154 
Electric sales to non-affiliates  1,447,482   1,332,364   1,315,141 
Other  454,896   217,666   108,732 
Total revenues  4,728,337   4,518,353   4,325,027 
             
EXPENSES:            
Fuel  1,127,463   1,315,293   1,087,010 
Purchased power from affiliates (Note 18)  222,406   101,409   234,090 
Purchased power from non-affiliates  996,383   778,882   764,090 
Other operating expenses  1,183,225   1,084,548   1,041,039 
Provision for depreciation  259,393   231,899   192,912 
General taxes  86,915   88,004   87,098 
Total expenses  3,875,785   3,600,035   3,406,239 
             
OPERATING INCOME  852,552   918,318   918,788 
             
OTHER INCOME (EXPENSE):            
Investment income (loss)  125,226   (22,678)  41,438 
Miscellaneous income  6,670   1,698   11,438 
Interest expense to affiliates (Note 18)  (10,106)  (29,829)  (65,501)
Interest expense - other  (142,120)  (111,682)  (92,199)
Capitalized interest  60,152   43,764   19,508 
Total other income (expense)  39,822   (118,727)  (85,316)
             
INCOME BEFORE INCOME TAXES  892,374   799,591   833,472 
             
INCOME TAXES  315,290   293,181   304,608 
             
NET INCOME $577,084  $506,410  $528,864 
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

152

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED BALANCE SHEETS

As of December 31, 2009  2008 
  (In thousands) 
ASSETS      
       
CURRENT ASSETS:      
Cash and cash equivalents $12  $39 
Receivables-        
Customers (less accumulated provisions of $12,041,000 and $5,899,000,        
respectively, for uncollectible accounts)  195,107   86,123 
Associated companies  318,561   378,100 
Other (less accumulated provisions of $6,702,000 and $6,815,000        
respectively, for uncollectible accounts)  51,872   24,626 
Notes receivable from associated companies  805,103   129,175 
Materials and supplies, at average cost  539,541   521,761 
Prepayments and other  107,782   112,535 
   2,017,978   1,252,359 
PROPERTY, PLANT AND EQUIPMENT:        
In service  10,357,632   9,871,904 
Less - Accumulated provision for depreciation  4,531,158   4,254,721 
   5,826,474   5,617,183 
Construction work in progress  2,423,446   1,747,435 
   8,249,920   7,364,618 
INVESTMENTS:        
Nuclear plant decommissioning trusts  1,088,641   1,033,717 
Long-term notes receivable from associated companies  -   62,900 
Other  22,466   61,591 
   1,111,107   1,158,208 
DEFERRED CHARGES AND OTHER ASSETS:        
Accumulated deferred income tax benefits  86,626   267,762 
Lease assignment receivable from associated companies  -   71,356 
Goodwill  24,248   24,248 
Property taxes  50,125   50,104 
Unamortized sale and leaseback costs  72,553   69,932 
Other  138,231   96,434 
   371,783   579,836 
  $11,750,788  $10,355,021 
LIABILITIES AND CAPITALIZATION        
         
CURRENT LIABILITIES:        
Currently payable long-term debt $1,550,927  $2,024,898 
Short-term borrowings-        
Associated companies  9,237   264,823 
Other  100,000   1,000,000 
Accounts payable-        
Associated companies  466,078   472,338 
Other  245,363   154,593 
Accrued taxes  83,158   79,766 
Other  359,057   248,439 
   2,813,820   4,244,857 
CAPITALIZATION (See Consolidated Statements of Capitalization):        
Common stockholder's equity  3,514,571   2,944,423 
Long-term debt and other long-term obligations  2,711,652   571,448 
   6,226,223   3,515,871 
NONCURRENT LIABILITIES:        
Deferred gain on sale and leaseback transaction  992,869   1,026,584 
Accumulated deferred investment tax credits  58,396   62,728 
Asset retirement obligations  921,448   863,085 
Retirement benefits  204,035   194,177 
Property taxes  50,125   50,104 
Lease market valuation liability  262,200   307,705 
Other  221,672   89,910 
   2,710,745   2,594,293 
COMMITMENTS AND CONTINGENCIES (Notes 7 & 15)        
  $11,750,788  $10,355,021 
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

153

FIRSTENERGY SOLUTIONS CORP. 
       
CONSOLIDATED STATEMENTS OF CAPITALIZATION 
       
As of December 31, 2009  2008 
  (In thousands) 
COMMON STOCKHOLDER'S EQUITY:      
Common stock, without par value, authorized 750 shares,      
7 shares outstanding $1,468,423  $1,464,229 
Accumulated other comprehensive loss (Note 2(F))  (103,001)  (91,871)
Retained earnings (Note 12(A))  2,149,149   1,572,065 
Total  3,514,571   2,944,423 
         
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS (Note 12(C)):        
Secured notes:        
    FirstEnergy Solutions Corp.        
 5.150% due 2009-2015  21,950   22,868 
         
 FirstEnergy Generation Corp.        
 5.700% due 2014  50,000   - 
 * 0.220% due 2017  28,525   28,525 
 ** 5.625% due 2018  141,260   141,260 
 * 0.230% due 2019  90,140   90,140 
 * 5.250% due 2023  50,000   - 
 ** 4.750% due 2029  100,000   100,000 
 ** 4.750% due 2029  6,450   6,450 
 * 0.220% due 2041  56,600   56,600 
   522,975   422,975 
         
    FirstEnergy Nuclear Generation Corp.        
 8.830% due 2009-2016  4,514   5,007 
 8.890% due 2009-2016  77,445   82,680 
 9.000% due 2009-2017  206,453   234,635 
 9.120% due 2009-2016  61,455   68,311 
 12.000% due 2009-2017  1,072   1,174 
* 0.330% due 2033  46,500   46,500 
 * 0.320% due 2033  54,600   54,600 
 * 0.350% due 2033  26,000   26,000 
 * 0.280% due 2033  99,100   99,100 
 * 0.280% due 2033  8,000   8,000 
 ** 5.750% due 2033  62,500   62,500 
 ** 5.875% due 2033  107,500   107,500 
 * 0.220% due 2034  7,200   7,200 
 * 0.230% due 2034  82,800   82,800 
 * 0.220% due 2035  72,650   72,650 
 * 0.270% due 2035  98,900   98,900 
 * 0.230% due 2035  60,000   60,000 
   1,076,689   1,117,557 
 Total secured notes  1,621,614   1,563,400 
         
Unsecured notes:        
FirstEnergy Solutions Corp.        
 4.800% due 2015  400,000   - 
 6.050% due 2021  600,000   - 
 6.800% due 2039  500,000   - 
   1,500,000   - 
FirstEnergy Generation Corp.        
 ** 3.000% due 2018  2,805   2,805 
 ** 3.000% due 2018  2,985   2,985 
 5.700% due 2020  177,000   - 
 * 0.400% due 2023  234,520   234,520 
 * 4.350% due 2028  15,000   15,000 
 * 7.125% due 2028  25,000   25,000 
 * 0.280% due 2040  43,000   43,000 
 * 0.230% due 2041  129,610   129,610 
 * 0.280% due 2041  26,000   26,000 
 ** 3.000% due 2047  46,300   46,300 
   702,220   525,220 
FirstEnergy Nuclear Generation Corp.        
 5.390% due to associated companies 2025  -   62,900 
 * 7.250% due 2032  23,000   23,000 
 * 7.250% due 2032  33,000   33,000 
 * 0.210% due 2033  135,550   135,550 
 * 0.240% due 2033  15,500   15,500 
 ** 3.000% due 2033  20,450   20,450 
 ** 3.000% due 2033  9,100   9,100 
 ** 0.220% due 2035  163,965   163,965 
   400,565   463,465 
 Total unsecured notes  2,602,785   988,685 
         
 Capital lease obligations (Note 7)  40,110   44,319 
 Net unamortized discount on debt  (1,930)  (58)
 Long-term debt due within one year  (1,550,927)  (2,024,898)
 Total long-term debt and other long-term obligations  2,711,652   571,448 
         
TOTAL CAPITALIZATION $6,226,223  $3,515,871 
*    Denotes variable rate issue with applicable year-end interest rate shown.
**   Denotes remarketed notes in 2009.
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
154

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

           Accumulated    
     Common Stock  Other    
  Comprehensive  Number  Carrying  Comprehensive  Retained 
  Income  of Shares  Value  Income (Loss)  Earnings 
  (Dollars in thousands) 
                
Balance, January 1, 2007     8   1,050,302   111,723   697,338 
Net income $528,864               528,864 
Net unrealized loss on derivative instruments, net                    
of $3,337,000 of income tax benefits  (5,640)          (5,640)    
Unrealized gain on investments, net of                    
$26,645,000 of income taxes  41,707           41,707     
Pension and other postretirement benefits, net                    
of $604,000 of income taxes (Note 3)  (7,136)          (7,136)    
Comprehensive income $557,795                 
Repurchase of common stock      (1)  (600,000)        
Equity contribution from parent          700,000         
Stock options exercised, restricted stock units                    
and other adjustments          4,141         
Consolidated tax benefit allocation          10,479         
Accounting for uncertainty in income taxes                    
cumulative effect adjustment                  (547)
Cash dividends declared on common stock                  (117,000)
Balance, December 31, 2007      7   1,164,922   140,654   1,108,655 
Net income $506,410               506,410 
Net unrealized loss on derivative instruments, net                    
of $5,512,000 of income tax benefits  (9,200)          (9,200)    
Change in unrealized gain on investments, net of                    
$82,014,000 of income tax benefits  (137,689)          (137,689)    
Pension and other postretirement benefits, net                    
of $47,853,000 of income tax benefits (Note 3)  (85,636)          (85,636)    
Comprehensive income $273,885                 
Equity contribution from parent          280,000         
Stock options exercised, restricted stock units                    
and other adjustments          13,262         
Consolidated tax benefit allocation          6,045         
Cash dividends declared on common stock                  (43,000)
Balance, December 31, 2008      7   1,464,229   (91,871)  1,572,065 
Net income $577,084               577,084 
Net unrealized gain on derivative instruments, net                    
of $6,766,000 of income taxes  11,329           11,329     
Change in unrealized gain on investments, net of                    
$20,937,000 of income tax benefits  (28,306)          (28,306)    
Pension and other postretirement benefits, net                    
of $8,472,000 of income taxes (Note 3)  5,847           5,847     
Comprehensive income $565,954                 
Restricted stock units          866         
Consolidated tax benefit allocation          3,328       - 
Balance, December 31, 2009      7  $1,468,423  $(103,001) $2,149,149 
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

155

FIRSTENERGY SOLUTIONS CORP. 
          
CONSOLIDATED STATEMENTS OF CASH FLOWS 
          
For the Years Ended December 31, 2009  2008  2007 
  (In thousands) 
          
CASH FLOWS FROM OPERATING ACTIVITIES:         
Net Income $577,084  $506,410  $528,864 
Adjustments to reconcile net income to net cash from            
operating activities-            
Provision for depreciation  259,393   231,899   192,912 
Nuclear fuel and lease amortization  130,486   111,978   100,720 
Deferred rents and lease market valuation liability  (46,384)  (43,263)  69 
Deferred income taxes and investment tax credits, net  219,962   116,626   (334,545)
Investment impairment (Note 2(E))  57,073   115,207   22,817 
Accrued compensation and retirement benefits  6,162   16,011   6,419 
Commodity derivative transactions, net (Note 6)  228,705   5,100   5,930 
Gain on asset sales  (10,649)  (38,858)  (12,105)
Gain on sales of investment securities held in trusts, net  (158,112)  (53,290)  (9,883)
Cash collateral, net  20,208   (60,621)  (31,059)
Pension trust contributions  -   -   (64,020)
Associated company lease assignment  71,356   -   - 
Decrease (increase) in operating assets-            
Receivables  (34,429)  59,782   (99,048)
Materials and supplies  12,513   (59,983)  56,407 
Prepayments and other current assets  (26,046)  (12,302)  (13,812)
Increase (decrease) in operating liabilities-            
Accounts payable  67,855   34,467   (104,599)
Accrued taxes  6,059   (90,568)  61,119 
Accrued interest  46,441   1,398   1,143 
Other  (53,388)  12,935   (13,012)
Net cash provided from operating activities  1,374,289   852,928   294,317 
             
CASH FLOWS FROM FINANCING ACTIVITIES:            
New Financing-            
Long-term debt  2,438,402   618,375   427,210 
Equity contributions from parent  -   280,000   700,000 
Short-term borrowings, net  -   700,759   - 
Redemptions and Repayments-            
Common stock  -   -   (600,000)
Long-term debt  (709,156)  (462,540)  (1,536,411)
Short-term borrowings, net  (1,155,586)  -   (458,321)
Common stock dividend payments  -   (43,000)  (117,000)
Other  (21,790)  (5,147)  (5,199)
Net cash provided from (used for) financing activities  551,870   1,088,447   (1,589,721)
             
CASH FLOWS FROM INVESTING ACTIVITIES:            
Property additions  (1,222,933)  (1,835,629)  (738,709)
Proceeds from asset sales  18,371   23,077   12,990 
Proceeds from sale and leaseback transaction  -   -   1,328,919 
Sales of investment securities held in trusts  1,379,154   950,688   655,541 
Purchases of investment securities held in trusts  (1,405,996)  (987,304)  (697,763)
Loan repayments from (loans to) associated companies  (675,928)  (36,391)  734,862 
Other  (18,854)  (55,779)  (436)
Net cash provided from (used for) investing activities  (1,926,186)  (1,941,338)  1,295,404 
             
Net change in cash and cash equivalents  (27)  37   - 
Cash and cash equivalents at beginning of year  39   2   2 
Cash and cash equivalents at end of year $12  $39  $2 
             
SUPPLEMENTAL CASH FLOW INFORMATION:            
Cash Paid During the Year-            
Interest (net of amounts capitalized) $38,446  $92,103  $136,121 
Income taxes $96,045  $196,963  $613,814 
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

156

OHIO EDISON COMPANY

MANAGEMENT’S NARRATIVE
CONSOLIDATED STATEMENTSANALYSIS OF INCOMERESULTS OF OPERATIONS

OE is a wholly owned electric utility subsidiary of FirstEnergy. OE engages in the distribution and sale of electric energy to communities in a 7,000 square mile area of central and northeastern Ohio and, through its wholly owned subsidiary, Penn, 1,100 square miles in western Pennsylvania. OE and Penn conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services and procurement of generation services for those franchise customers electing to retain them as their power supplier. The areas served by OE and Penn have populations of approximately 2.3 million and 0.4 million, respectively.
For the Years Ended December 31, 2009  2008  2007 
  (In thousands) 
REVENUES (Note 18):         
Electric sales $2,418,292  $2,487,956  $2,375,306 
Excise and gross receipts tax collections  98,630   113,805   116,223 
Total revenues  2,516,922   2,601,761   2,491,529 
             
EXPENSES (Note 18):            
Purchased power from affiliates  991,405   1,203,314   1,261,439 
Purchased power from non-affiliates  481,406   114,972   98,344 
Other operating costs  461,142   565,893   567,726 
Provision for depreciation  89,289   79,444   77,405 
Amortization of regulatory assets, net  93,694   117,733   14,252 
General taxes  171,082   186,396   181,104 
Total expenses  2,288,018   2,267,752   2,200,270 
             
OPERATING INCOME  228,904   334,009   291,259 
             
OTHER INCOME (EXPENSE) (Note 18):            
Investment income  46,887   56,103   85,848 
Miscellaneous income (expense)  2,654   (4,525)  5,073 
Interest expense  (90,669)  (75,058)  (83,343)
Capitalized interest  844   414   266 
Total other income (expense)  (40,284)  (23,066)  7,844 
             
INCOME BEFORE INCOME TAXES  188,620   310,943   299,103 
             
INCOME TAXES  66,186   98,584   101,273 
             
NET INCOME  122,434   212,359   197,830 
             
Noncontrolling interest income  567   613   664 
             
EARNINGS AVAILABLE TO PARENT $121,867  $211,746  $197,166 
For additional information with respect to OE, 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: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Contractual Obligations, Off-Balance Sheet Arrangements, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
Results of Operations
Net income decreased by $27 million in 2011 compared to 2010. The decrease primarily resulted from lower revenues and higher other operating expenses, partially offset by lower purchased power costs.
Revenues
Revenues decreased by $203 million, or 11%, in 2011 compared with 2010 due to lower retail generation revenues, partially offset by higher distribution and wholesale generation revenues.
Distribution revenues increased by $69 million in 2011, compared to 2010, due to increased MWH deliveries and higher average prices in all customer classes. The higher MWH deliveries in the residential class were driven primarily by increased load growth partially offset by lower weather-related usage. The increase in distribution deliveries to commercial and industrial customers was primarily due to recovering economic conditions in OE’s and Penn’s service territories. Higher average prices in all customer classes were principally due to the recovery of deferred distribution costs.
Changes in distribution MWH deliveries and revenues in 2011 compared to 2010, are summarized in the following tables:

The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
Distribution MWH DeliveriesIncrease
Residential0.3%
Commercial0.7%
Industrial5.4%
Increase in Distribution Deliveries2.0%

157
Distribution Revenues Increase
  (In millions)
Residential $26
Commercial 17
Industrial 26
Increase in Distribution Revenues $69

OHIO EDISON COMPANY 
       
CONSOLIDATED BALANCE SHEETS 
       
As of December 31, 2009  2008 
  (In thousands) 
ASSETS      
CURRENT ASSETS:      
Cash and cash equivalents $324,175  $146,343 
Receivables-        
Customers (less accumulated provisions of $5,119,000 and $6,065,000, respectively,        
for uncollectible accounts)  209,384   277,377 
Associated companies  98,874   234,960 
Other (less accumulated provisions of $18,000 and $7,000, respectively,        
for uncollectible accounts)  14,155   14,492 
Notes receivable from associated companies  118,651   222,861 
Prepayments and other  15,964   5,452 
   781,203   901,485 
UTILITY PLANT:        
In service  3,036,467   2,903,290 
Less - Accumulated provision for depreciation  1,165,394   1,113,357 
   1,871,073   1,789,933 
Construction work in progress  31,171   37,766 
   1,902,244   1,827,699 
OTHER PROPERTY AND INVESTMENTS:        
Long-term notes receivable from associated companies  -   256,974 
Investment in lease obligation bonds (Note 7)  216,600   239,625 
Nuclear plant decommissioning trusts  120,812   116,682 
Other  96,861   100,792 
   434,273   714,073 
DEFERRED CHARGES AND OTHER ASSETS:        
Regulatory assets  465,331   575,076 
Pension assets (Note 3)  19,881   - 
Property taxes  67,037   60,542 
Unamortized sale and leaseback costs  35,127   40,130 
Other  39,881   33,710 
   627,257   709,458 
  $3,744,977  $4,152,715 
LIABILITIES AND CAPITALIZATION        
CURRENT LIABILITIES:        
Currently payable long-term debt $2,723  $101,354 
Short-term borrowings-        
Associated companies  92,863   - 
Other  807   1,540 
Accounts payable-        
Associated companies  102,763   131,725 
Other  40,423   26,410 
Accrued taxes  81,868   77,592 
Accrued interest  25,749   25,673 
Other  81,424   85,209 
   428,620   449,503 
CAPITALIZATION (See Consolidated Statements of Capitalization):
        
Common stockholder's equity  1,021,110   1,294,054 
Noncontrolling interest  6,442   7,106 
Total equity  1,027,552   1,301,160 
Long-term debt and other long-term obligations  1,160,208   1,122,247 
   2,187,760   2,423,407 
NONCURRENT LIABILITIES:        
Accumulated deferred income taxes  660,114   653,475 
Accumulated deferred investment tax credits  11,406   13,065 
Asset retirement obligations  85,926   80,647 
Retirement benefits  174,925   308,450 
Other  196,226   224,168 
   1,128,597   1,279,805 
         
COMMITMENTS AND CONTINGENCIES (Notes 7 and 15)        
         
  $3,744,977  $4,152,715 
Retail generation revenues decreased by $277 million primarily due to a decrease in MWH sales from increased customer shopping and lower average prices in all customer classes. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. OE and Penn defer the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings. Lower MWH sales were primarily the result of increased customer shopping in 2011. The increases in shopping by residential, commercial and industrial customers were 18%, 11% and 7%, respectively, in 2011 compared with 2010.


108


Decreases in retail generation MWH sales and revenues in 2011 compared to 2010 are summarized in the following tables:
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
Retail Generation MWH SalesDecrease
Residential(28.8)%
Commercial(34.0)%
Industrial(22.6)%
Decrease in Retail Generation Sales(28.3)%

158
Retail Generation Revenues Decrease
  (In millions)
Residential $(166)
Commercial (74)
Industrial (37)
Decrease in Retail Generation Revenues $(277)

OHIO EDISON COMPANY
       
CONSOLIDATED STATEMENTS OF CAPITALIZATION
       
As of December 31, 2009  2008 
  (In thousands) 
COMMON STOCKHOLDER'S EQUITY:      
Common stock, without par value, 175,000,000 shares authorized,      
60 shares outstanding $1,154,797  $1,224,416 
Accumulated other comprehensive loss (Note 2(F))  (163,577)  (184,385)
Retained earnings (Note 12(A))  29,890   254,023 
Total  1,021,110   1,294,054 
         
NONCONTROLLING INTEREST  6,442   7,106 
         
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS (Note 12(C)):        
Ohio Edison Company-        
First mortgage bonds:        
8.250% due 2018  25,000   25,000 
8.250% due 2038  275,000   275,000 
Total  300,000   300,000 
         
Secured notes:        
7.156% weighted average interest rate due 2009-2010  1,257   1,324 
Total  1,257   1,324 
         
Unsecured notes:        
*  3.000% due 2014  -   50,000 
   5.450% due 2015  150,000   150,000 
   6.400% due 2016  250,000   250,000 
*  1.500% due 2023  -   50,000 
   6.875% due 2036  350,000   350,000 
  Total  750,000   850,000 
         
Pennsylvania Power Company-        
First mortgage bonds:        
9.740% due 2009-2019  9,773   10,747 
6.090% due 2022  100,000   - 
7.625% due 2023  6,500   6,500 
Total  116,273   17,247 
         
Secured notes:
        
5.400% due 2013  1,000   1,000 
Total  1,000   1,000 
         
Unsecured notes:        
5.390% due 2010 to associated company  -   62,900 
Total  -   62,900 
         
Capital lease obligations (Note 7)  6,884   4,219 
Net unamortized discount on debt  (12,483)  (13,089)
Long-term debt due within one year  (2,723)  (101,354)
Total long-term debt and other long-term obligations  1,160,208   1,122,247 
TOTAL CAPITALIZATION $2,187,760  $2,423,407 
Wholesale generation revenues increased by $12 million in 2011 compared to 2010 due to higher revenues from sales to NGC from OE’s leasehold interests in Perry Unit 1 and Beaver Valley Unit 2.
Operating Expenses
* Denotes variable rate issue with applicable year-end interest rate shown.Total operating expenses decreased by $175 million in 2011 compared to 2010. The following table presents changes from the prior year by expense category:
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

159

OHIO EDISON COMPANY 
                
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY 
                
           Accumulated 
     Common Stock  Other    
  Comprehensive Number  Carrying  Comprehensive  Retained 
  Income  of Shares  Value  Income (Loss)  Earnings 
  (Dollars in thousands) 
Balance, January 1, 2007     80  $1,708,441  $3,208  $260,736 
Earnings available to parent $197,166               197,166 
Unrealized gain on investments, net of                 
$2,784,000 of income taxes  3,874           3,874     
Pension and other postretirement benefits, net             
of $37,820,000 of income taxes (Note 3)  41,304           41,304     
Comprehensive income available to parent $242,344                 
Restricted stock units          129         
Stock-based compensation          17         
Repurchase of common stock      (20)  (500,000)        
Consolidated tax benefit allocation       11,925         
Accounting for uncertainty in income taxes                 
cumulative effect adjustment                  (625)
Cash dividends declared on common stock               (150,000)
Balance, December 31, 2007      60   1,220,512   48,386   307,277 
Earnings available to parent $211,746               211,746 
Change in unrealized gain on investments, net of             
$5,702,000 of income tax benefits  (10,370)          (10,370)    
Pension and other postretirement benefits, net             
of $121,425,000 of income tax benefits (Note 3)  (222,401)          (222,401)    
Comprehensive loss $(21,025)                
Restricted stock units          (16)        
Stock-based compensation          1         
Consolidated tax benefit allocation       3,919         
Cash dividends declared on common stock               (265,000)
Balance, December 31, 2008      60   1,224,416   (184,385)  254,023 
Earnings available to parent $121,867               121,867 
Change in unrealized gain on investments, net of             
$4,196,000 of income tax benefits  (5,497)          (5,497)    
Pension and other postretirement benefits, net
             
of $20,257,000 of income taxes (Note 3)  26,305           26,305     
Comprehensive income available to parent $142,675                 
Restricted stock units          81         
Consolidated tax benefit allocation       4,300         
Cash dividends declared on common stock               (346,000)
Cash dividends declared as return of capital      (74,000)        
Balance, December 31, 2009      60  $1,154,797  $(163,577) $29,890 
                     
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements. 
160
OHIO EDISON COMPANY 
          
CONSOLIDATED STATEMENTS OF CASH FLOWS 
          
For the Years Ended December 31, 2009  2008  2007 
  (In thousands) 
          
CASH FLOWS FROM OPERATING ACTIVITIES:         
Net income $122,434  $212,359  $197,830 
Adjustments to reconcile net income to net cash from operating activities-            
Provision for depreciation  89,289   79,444   77,405 
Amortization of regulatory assets, net  93,694   117,733   14,252 
Purchased power cost recovery reconciliation  4,113   -   - 
Amortization of lease costs  (8,211)  (7,702)  (7,425)
Deferred income taxes and investment tax credits, net  41,178   16,125   423 
Accrued compensation and retirement benefits  (13,729)  17,139   (46,313)
Accrued regulatory obligations  18,635   -   - 
Electric service prepayment programs  (4,634)  (42,215)  (39,861)
Cash collateral from suppliers  6,469   -   - 
Pension trust contributions  (103,035)  -   (20,261)
Decrease (increase) in operating assets-            
Receivables  139,679   (61,926)  (57,461)
Prepayments and other current assets  (10,407)  5,937   3,265 
Increase (decrease) in operating liabilities-            
Accounts payable  (14,949)  14,166   15,649 
Accrued taxes  (9,142)  (8,983)  (81,079)
Accrued interest  76   3,295   (2,334)
Other  4,811   143   7,229 
Net cash provided from operating activities  356,271   345,515   61,319 
             
CASH FLOWS FROM FINANCING ACTIVITIES:            
New Financing-            
Long-term debt  100,000   292,169   - 
Short-term borrowings, net  92,130   -   - 
Redemptions and Repayments-            
Common stock  -   -   (500,000)
Long-term debt  (101,680)  (249,897)  (112,497)
Short-term borrowings, net  -   (51,761)  (114,475)
Dividend Payments-            
Common stock  (420,000)  (315,000)  (100,000)
Other  (2,839)  (4,435)  (1,764)
Net cash used for financing activities  (332,389)  (328,924)  (828,736)
             
CASH FLOWS FROM INVESTING ACTIVITIES:            
Property additions  (152,817)  (182,512)  (145,311)
Sales of investment securities held in trusts  131,478   120,744   37,736 
Purchases of investment securities held in trusts  (138,925)  (127,680)  (43,758)
Loan repayments from (loans to) associated companies, net  102,314   373,138   (79,115)
Collection of principal on long-term notes receivable  195,970   1,756   960,327 
Cash investments  20,133   (57,792)  37,499 
Other  (4,203)  1,366   59 
Net cash provided from investing activities  153,950   129,020   767,437 
             
Net increase (decrease) in cash and cash equivalents  177,832   145,611   20 
Cash and cash equivalents at beginning of year  146,343   732   712 
Cash and cash equivalents at end of year $324,175  $146,343  $732 
             
SUPPLEMENTAL CASH FLOW INFORMATION:            
Cash Paid During the Year-            
Interest (net of amounts capitalized) $86,523  $67,508  $80,958 
Income taxes $20,530  $118,834  $133,170 
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

161
Operating Expenses - Changes Increase (Decrease)
  (In millions)
Purchased power costs $(279)
Other operating expenses 109
Pensions and OPEB mark-to-market adjustment 19
Provision for depreciation 2
Amortization of regulatory assets, net (33)
General taxes 7
Net Decrease in Operating Expenses $(175)

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
          
CONSOLIDATED STATEMENTS OF OPERATIONS
          
For the Years Ended December 31, 2009  2008  2007 
  (In thousands) 
REVENUES (Note 18):         
Electric sales $1,609,946  $1,746,309  $1,753,385 
Excise tax collections  66,192   69,578   69,465 
Total revenues  1,676,138   1,815,887   1,822,850 
             
EXPENSES (Note 18):            
Purchased power from affiliates  734,592   766,270   738,709 
Purchased power from non-affiliates  245,809   4,210   9,505 
Other operating costs  161,407   259,438   350,825 
Provision for depreciation  71,908   72,383   75,238 
Amortization of regulatory assets  370,967   163,534   144,370 
Deferral of new regulatory assets  (134,587)  (107,571)  (149,556)
General taxes  145,324   143,058   141,551 
Total expenses  1,595,420   1,301,322   1,310,642 
             
OPERATING INCOME  80,718   514,565   512,208 
             
OTHER INCOME (EXPENSE) (Note 18):            
Investment income  31,194   34,392   57,724 
Miscellaneous income (expense)  3,911   (495)  9,773 
Interest expense  (137,171)  (125,976)  (138,977)
Capitalized interest  173   786   918 
Total other expense  (101,893)  (91,293)  (70,562)
             
INCOME (LOSS) BEFORE INCOME TAXES  (21,175)  423,272   441,646 
             
INCOME TAX EXPENSE (BENEFIT)  (10,183)  136,786   163,363 
             
NET INCOME (LOSS)  (10,992)  286,486   278,283 
             
Noncontrolling interest income  1,714   1,960   1,871 
             
EARNINGS (LOSS) APPLICABLE TO PARENT $(12,706) $284,526  $276,412 
Purchased power costs decreased in 2011 compared to 2010 due to lower MWH purchases resulting from reduced generation sales requirements coupled with lower unit costs. The increase in other operating expenses in 2011 compared to the same period of 2010 was principally due to expenses associated with nuclear refueling outages at OE’s leased Perry Unit 1 and Beaver Valley Unit 2 that were absent in 2010. Decreased pensions and OPEB mark-to-market adjustment charges are the result of lower net actuarial losses in 2011 compared to 2010. The amortization of regulatory assets decreased primarily due to higher deferred residential generation credits in 2011. General taxes increased as a result of higher property taxes.
Interest Rate Risk
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.OE’s exposure to fluctuations in market interest rates is reduced since all of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for OE’s investment portfolio and debt obligations.

162

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY 
       
CONSOLIDATED BALANCE SHEETS 
       
As of December 31, 2009  2008 
  (In thousands) 
ASSETS      
CURRENT ASSETS:      
Cash and cash equivalents $86,230  $226 
Receivables-        
Customers (less accumulated provisions of $5,239,000 and        
$5,916,000, respectively, for uncollectible accounts)  209,335   276,400 
Associated companies  98,954   113,182 
Other  11,661   13,834 
Notes receivable from associated companies  26,802   19,060 
Prepayments and other  9,973   2,787 
   442,955   425,489 
UTILITY PLANT:        
In service  2,310,074   2,221,660 
Less - Accumulated provision for depreciation  888,169   846,233 
   1,421,905   1,375,427 
Construction work in progress  36,907   40,651 
   1,458,812   1,416,078 
OTHER PROPERTY AND INVESTMENTS:        
Investment in lessor notes (Note 7)  388,641   425,715 
Other  10,220   10,249 
   398,861   435,964 
DEFERRED CHARGES AND OTHER ASSETS:        
Goodwill  1,688,521   1,688,521 
Regulatory assets  545,505   783,964 
Pension assets (Note 3)  13,380   - 
Property taxes  77,319   71,500 
Other  12,777   10,818 
   2,337,502   2,554,803 
  $4,638,130  $4,832,334 
LIABILITIES AND CAPITALIZATION        
CURRENT LIABILITIES:        
Currently payable long-term debt $117  $150,688 
Short-term borrowings-        
Associated companies  339,728   227,949 
Accounts payable-        
Associated companies  68,634   106,074 
Other  17,166   7,195 
Accrued taxes  90,511   87,810 
Accrued interest  18,466   13,932 
Other  45,440   40,095 
   580,062   633,743 
CAPITALIZATION (See Consolidated Statements of Capitalization):
        
Common stockholder's equity  1,343,987   1,603,882 
Noncontrolling interest  20,592   22,555 
Total equity  1,364,579   1,626,437 
Long-term debt and other long-term obligations  1,872,750   1,591,586 
   3,237,329   3,218,023 
NONCURRENT LIABILITIES:        
Accumulated deferred income taxes  644,745   704,270 
Accumulated deferred investment tax credits  11,836   13,030 
Retirement benefits  69,733   128,738 
Deferred revenues - electric service programs  -   3,510 
Lease assignment payable to associated companies (Note 7)  -   40,827 
Other  94,425   90,193 
   820,739   980,568 
         
COMMITMENTS AND CONTINGENCIES (Notes 7 and 15)        
         
  $4,638,130  $4,832,334 
109
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

163
Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income $31
 $36
 $42
 $37
 $13
 $138
 $297
 $318
Average interest rate 8.7% 8.8% 8.8% 8.9% 8.9% 4.4% 6.8%  
Liabilities:                
Long-term Debt:                
Fixed rate       $150
 $250
 $757
 $1,157
 $1,434
Average interest rate       5.5% 6.4% 7.3% 6.9%  
Equity Price Risk
NDT funds have been established to satisfy nuclear decommissioning obligations. Included in OE’s NDT are fixed income and short-term investments carried at market values of approximately $134 million and $1 million, respectively, as of December 31, 2011, excluding $2 million of net receivables, payables and accrued income. OE recognizes in earnings the unrealized losses on available-for-sale securities held in its NDT as OTTI. A decline in the value of OE's NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During 2011, approximately $4 million was contributed to OE's NDT to comply with requirements under certain sale-leaseback transactions in which OE continues as a lessee.
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. OE evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. OE may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. OE monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.


110


THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

MANAGEMENT’S NARRATIVE
CONSOLIDATED STATEMENTSANALYSIS OF CAPITALIZATIONRESULTS OF OPERATIONS
CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI provides regulated electric distribution services in an area of 1,600 square miles in northeastern Ohio. The area it serves has a population of approximately 1.7 million. CEI also procures generation services for those customers electing to retain them 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: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Contractual Obligations, Off-Balance Sheet Arrangements, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
On January 25, 2012, CEI filed a Form 15 with the SEC to deregister its securities and suspend its obligation to file periodic reports under the Securities Exchange Act of 1934, as amended, except that the registrant has filed this Annual Report on Form 10-K for the year ended December 31, 2011. This Annual Report on Form 10-K will be the last filing made by CEI with the SEC under the Exchange Act.
Results of Operations
Earnings available to parent decreased by $5 million in 2011 compared to 2010. The decrease in earnings was primarily due to decreased revenues, partially offset by lower purchased power costs and amortization of regulatory assets.
Revenues
Revenues decreased $345 million, or 28%, in 2011 compared to 2010 due to lower retail generation and distribution revenues.
Distribution revenues decreased $78 million in 2011 compared to 2010 due to lower average unit prices in all customer classes offset by increased MWH deliveries to the industrial sector. The lower average unit prices were the result of the absence of transition charges in 2011. Lower residential and commercial deliveries resulted from decreased weather-related usage in 2011. In the industrial sector, MWH deliveries increased primarily as a result of recovering economic conditions in CEI's service territory.
Changes in distribution MWH deliveries and revenues in 2011 compared to 2010 are summarized in the following tables:
Distribution MWH DeliveriesIncrease (Decrease)
Residential(0.3)%
Commercial(0.4)%
Industrial1.4 %
Net Increase in Distribution Deliveries0.2 %
Distribution Revenues Decrease
  (In millions)
Residential $(12)
Commercial (7)
Industrial (59)
Decrease in Distribution Revenues $(78)
Retail generation revenues decreased $265 million in 2011 as compared to 2010 primarily due to lower MWH sales to all customer classes that resulted from increased customer shopping and lower average unit prices for the commercial and residential customer classes. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. CEI defers the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings. Lower MWH sales were the result of increased shopping by residential, commercial and industrial customers of 15%, 8% and 36%, respectively, in 2011 compared to 2010. Lower average unit prices in the residential customer class were primarily due to the lower auction price in 2011.


As of December 31, 2009  2008 
  (In thousands) 
       
COMMON STOCKHOLDER'S EQUITY:      
Common stock, without par value, 105,000,000 shares authorized,      
67,930,743 shares outstanding $884,897  $878,785 
Accumulated other comprehensive loss (Note 2(F))  (138,158)  (134,857)
Retained earnings (Note 12(A))  597,248   859,954 
Total  1,343,987   1,603,882 
         
NONCONTROLLING INTEREST  20,592   22,555 
         
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS (Note 12(C)):        
First mortgage bonds-        
8.875% due 2018  300,000   300,000 
5.500% due 2024  300,000   - 
Total  600,000   300,000 
         
Secured notes-        
7.430% due 2009  -   150,000 
7.880% due 2017  300,000   300,000 
Total  300,000   450,000 
         
Unsecured notes-        
5.650% due 2013  300,000   300,000 
5.700% due 2017  250,000   250,000 
5.950% due 2036  300,000   300,000 
7.664% due to associated companies 2009-2016 (Note 8)  123,008   141,210 
Total  973,008   991,210 
         
         
Capital lease obligations (Note 7)  3,162   3,062 
Net unamortized discount on debt  (3,303)  (1,998)
Long-term debt due within one year  (117)  (150,688)
Total long-term debt and other long-term obligations  1,872,750   1,591,586 
TOTAL CAPITALIZATION $3,237,329  $3,218,023 
111


Changes in retail generation sales and revenues in 2011 compared to 2010 are summarized in the following tables:
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
Retail Generation MWH SalesDecrease
Residential(38.8)%
Commercial(37.6)%
Industrial(71.3)%
Decrease in Retail Generation Sales(52.2)%

164
Retail Generation Revenues Decrease
  (In millions)
Residential $(88)
Commercial (77)
Industrial (100)
Decrease in Retail Generation Revenues $(265)
Operating Expenses
Total operating expenses decreased $336 million in 2011 compared to 2010. The following table presents changes from the prior year by expense category:
Operating Expenses - Changes 
Increase
(Decrease)
  (In millions)
Purchased power costs $(254)
Other operating costs 15
Pensions and OPEB mark-to-market adjustment 8
Provision for depreciation 1
Amortization of regulatory assets, net (117)
General taxes 11
Net Decrease in Operating Expenses $(336)
Purchased power costs decreased in 2011 primarily due to lower MWH purchases resulting from reduced sales requirements as a result of increased customer shopping. Other operating expenses increased due to 2011 inventory valuation adjustments. Increased pensions and OPEB mark-to-market adjustment changes were due to higher net actuarial losses in 2011 as compared to 2010. Amortization of regulatory assets decreased primarily due to the completion of transition cost recovery at the end of 2010 and higher deferred purchased power costs in 2011, partially offset by increased recovery of deferred distribution costs and the absence in 2011 of renewable energy credit expenses that were deferred in 2010. General taxes increased due to increased property taxes as compared to 2010.
Interest Rate Risk
CEI's exposure to fluctuations in market interest rates is reduced since all of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for CEI’s investment portfolio and debt obligations.


THE CLEVELAND ELECTRIC ILLUMINATING COMPANY 
                
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY 
                
           Accumulated    
     Common Stock  Other    
  Comprehensive  Number  Carrying  Comprehensive  Retained 
  Income  of Shares  Value  Income (Loss)  Earnings 
  (Dollars in thousands) 
                
Balance, January 1, 2007     67,930,743  $860,133  $(104,431) $713,201 
Earnings available to parent $276,412               276,412 
Pension and other postretirement benefits, net                    
of $30,705,000 of income taxes (Note 3)  35,302           35,302     
Comprehensive income $311,714                 
Restricted stock units          184         
Stock-based compensation          10         
Consolidated tax benefit allocation          13,209         
Accounting for uncertainty in income taxes                    
cumulative effect adjustment                  (185)
Cash dividends declared on common stock                  (304,000)
Balance, December 31, 2007      67,930,743   873,536   (69,129)  685,428 
Earnings available to parent $284,526               284,526 
Pension and other postretirement benefits, net                    
of $33,136,000 of income tax benefits (Note 3)  (65,728)          (65,728)    
Comprehensive income $218,798                 
Restricted stock units          (1)        
Stock-based compensation          1         
Consolidated tax benefit allocation          5,249         
Cash dividends declared on common stock                  (110,000)
Balance, December 31, 2008      67,930,743   878,785   (134,857)  859,954 
Loss applicable to parent $(12,706)              (12,706)
Pension and other postretirement benefits, net                    
of $1,923,000 of income tax benefits (Note 3)  (3,301)          (3,301)    
Comprehensive loss $(16,007)                
Restricted stock units          74         
Consolidated tax benefit allocation          6,038         
Cash dividends declared on common stock                  (250,000)
Balance, December 31, 2009      67,930,743  $884,897  $(138,158) $597,248 
112
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

165
Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income $66
 $75
 $80
 $50
 $16
   $287
 $315
Average interest rate 7.7% 7.7% 7.7% 7.7% 8.0%   7.7%  
Liabilities:                
Long-term Debt:                
Fixed rate   $325
 $26
 $24
 $6
 $1,450
 $1,831
 $2,162
Average interest rate   5.8% 7.7% 7.7% 7.7% 6.8% 6.7%  
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. CEI evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. CEI may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. CEI monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS113

For the Years Ended December 31, 2009  2008  2007 
  (In thousands) 
CASH FLOWS FROM OPERATING ACTIVITIES:         
Net income (loss) $(10,992) $286,486  $278,283 
Adjustments to reconcile net income (loss) to net cash from operating activities-            
Provision for depreciation  71,908   72,383   75,238 
Amortization of regulatory assets  370,967   163,534   144,370 
Deferral of new regulatory assets  (134,587)  (107,571)  (149,556)
Deferred rents and lease market valuation liability  -   -   (357,679)
Purchased power cost recovery reconciliation  (5,086)  -   - 
Deferred income taxes and investment tax credits, net  (51,839)  11,918   (22,767)
Accrued compensation and retirement benefits  8,514   1,563   3,196 
Electric service prepayment programs  (3,510)  (23,634)  (24,443)
Pension trust contributions  (89,789)  -   (24,800)
Accrued regulatory obligations  12,556   -   - 
Cash collateral from suppliers  5,440   -   - 
Lease assignment payments to associated company  (40,827)  -   - 
Decrease (increase) in operating assets-            
Receivables  65,603   66,963   209,426 
Prepayments and other current assets  (7,186)  (450)  (152)
Increase (decrease) in operating liabilities-            
Accounts payable  (3,479)  13,787   (316,638)
Accrued taxes  2,533   (3,149)  (33,659)
Accrued interest  4,534   37   (5,138)
Other  12,116   8,202   2,438 
Net cash provided from (used for) operating activities  206,876   490,069   (221,881)
             
CASH FLOWS FROM FINANCING ACTIVITIES:            
New Financing-            
Long-term debt  298,398   300,000   249,602 
Short-term borrowings, net  93,577   -   277,581 
Redemptions and Repayments-            
Long-term debt  (151,273)  (213,319)  (492,825)
Short-term borrowings, net  -   (315,827)  - 
Dividend Payments-            
Common stock  (275,000)  (185,000)  (204,000)
Other  (6,427)  (6,440)  (6,312)
Net cash used for financing activities  (40,725)  (420,586)  (175,954)
             
CASH FLOWS FROM INVESTING ACTIVITIES:            
Property additions  (103,243)  (137,265)  (149,131)
Loan repayments from (loans to) associated companies, net  (7,741)  33,246   6,714 
Collection of principal on long-term notes receivable  -   -   486,634 
Investments in lessor notes  37,074   37,707   56,179 
Other  (6,237)  (3,177)  (2,550)
Net cash provided from (used for) investing activities  (80,147)  (69,489)  397,846 
             
Net increase (decrease) in cash and cash equivalents  86,004   (6)  11 
Cash and cash equivalents at beginning of year  226   232   221 
Cash and cash equivalents at end of year $86,230  $226  $232 
             
SUPPLEMENTAL CASH FLOW INFORMATION:            
Cash Paid During the Year-            
Interest (net of amounts capitalized) $130,689  $122,834  $141,390 
Income taxes $29,358  $153,042  $186,874 
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

166

THE TOLEDO EDISON COMPANY

MANAGEMENT’S NARRATIVE
CONSOLIDATED STATEMENTSANALYSIS OF INCOMERESULTS OF OPERATIONS

TE is a wholly owned electric utility subsidiary of FirstEnergy. TE provides regulated electric distribution services in an area of 2,300 square miles in northwestern Ohio. The area it serves has a population of approximately 0.7 million. TE also provides generation services to those customers electing to retain them as their power supplier.
For the Years Ended December 31, 2009  2008  2007 
  (In thousands) 
REVENUES (Note 18):         
Electric sales $810,069  $865,016  $934,772 
Excise tax collections  23,839   30,489   29,173 
Total revenues  833,908   895,505   963,945 
             
EXPENSES (Note 18):            
Purchased power from affiliates  392,825   410,885   392,430 
Purchased power from non-affiliates  136,210   2,459   5,993 
Other operating costs  142,203   190,441   279,047 
Provision for depreciation  30,727   32,422   36,743 
Amortization of regulatory assets, net  37,820   94,104   41,684 
General taxes  47,815   52,324   50,640 
Total expenses  787,600   782,635   806,537 
             
OPERATING INCOME  46,308   112,870   157,408 
             
OTHER INCOME (EXPENSE) (Note 18):            
Investment income  24,388   22,823   27,713 
Miscellaneous expense  (2,436)  (7,820)  (6,648)
Interest expense  (36,512)  (23,286)  (34,135)
Capitalized interest  169   164   640 
Total other expense  (14,391)  (8,119)  (12,430)
             
INCOME BEFORE INCOME TAXES  31,917   104,751   144,978 
             
INCOME TAXES  7,939   29,824   53,736 
             
NET INCOME  23,978   74,927   91,242 
             
Noncontrolling interest income  21   12   3 
             
EARNINGS AVAILABLE TO PARENT $23,957  $74,915  $91,239 
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: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Contractual Obligations, Off-Balance Sheet Arrangements, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
On January 25, 2012, TE filed a Form 15 with the SEC to deregister its securities and suspend its obligation to file periodic reports under the Securities Exchange Act of 1934, as amended, except that the registrant has filed this Annual Report on Form 10-K for the year ended December 31, 2011. This Annual Report on Form 10-K will be the last filing made by TE with the SEC under the Exchange Act.
Results of Operations
Earnings available to parent decreased by $2 million in 2011 compared to 2010. The decrease was primarily from lower revenues and higher other operating expenses, partially offset by lower purchased power costs from affiliates.
Revenues
Revenues decreased $40 million, or 8%, in 2011 compared to 2010, primarily due to lower retail generation sales, partially offset by an increase in distribution revenues.
Distribution revenues increased $28 million in 2011 compared to 2010, primarily due to higher MWH deliveries to residential and industrial customers and higher unit prices to all customer classes related to increased energy efficiency rider rates, partially offset by lower MWH deliveries to commercial customers. Higher MWH deliveries to residential customers reflected increased load growth slightly offset by lower weather-related usage that also drove lower deliveries to commercial customers. In the industrial sector, MWH deliveries increased primarily as a result of recovering economic conditions in TE's service territory.
Changes in distribution MWH deliveries and revenues in 2011 compared to 2010 are summarized in the following tables:
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

167
THE TOLEDO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS

As of December 31, 2009  2008 
  (In thousands) 
ASSETS      
CURRENT ASSETS:      
Cash and cash equivalents $436,712  $14 
Receivables-        
Customers  75   751 
Associated companies  90,191   61,854 
Other (less accumulated provisions of $208,000 and $203,000,        
respectively, for uncollectible accounts)  20,180   23,336 
Notes receivable from associated companies  85,101   111,579 
Prepayments and other  7,111   1,213 
   639,370   198,747 
UTILITY PLANT:        
In service  912,930   870,911 
Less - Accumulated provision for depreciation  427,376   407,859 
   485,554   463,052 
Construction work in progress  9,069   9,007 
   494,623   472,059 
OTHER PROPERTY AND INVESTMENTS:        
Investment in lessor notes (Note 7)  124,357   142,687 
Long-term notes receivable from associated companies  -   37,233 
Nuclear plant decommissioning trusts  73,935   73,500 
Other  1,580   1,668 
   199,872   255,088 
DEFERRED CHARGES AND OTHER ASSETS:        
Goodwill  500,576   500,576 
Regulatory assets  69,557   109,364 
Property taxes  23,658   22,970 
Other  55,622   51,315 
   649,413   684,225 
  $1,983,278  $1,610,119 
LIABILITIES AND CAPITALIZATION        
CURRENT LIABILITIES:        
Currently payable long-term debt $222  $34 
Accounts payable-        
Associated companies  78,341   70,455 
Other  8,312   4,812 
Notes payable to associated companies  225,975   111,242 
Accrued taxes  25,734   24,433 
Lease market valuation liability  36,900   36,900 
Other  29,273   22,489 
   404,757   270,365 
CAPITALIZATION (See Statements of Capitalization):
        
Common stockholder's equity  489,878   480,050 
Noncontrolling interest  2,696   2,675 
Total equity  492,574   482,725 
Long-term debt and other long-term obligations  600,443   299,626 
   1,093,017   782,351 
NONCURRENT LIABILITIES:        
Accumulated deferred income taxes  80,508   78,905 
Accumulated deferred investment tax credits  6,367   6,804 
Lease market valuation liability (Note 7)  236,200   273,100 
Retirement benefits  65,988   73,106 
Asset retirement obligations  32,290   30,213 
Lease assignment payable to associated companies  -   30,529 
Other  64,151   64,746 
   485,504   557,403 
COMMITMENTS AND CONTINGENCIES (Notes 7 and 15)        
  $1,983,278  $1,610,119 
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

168

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION

As of December 31, 2009  2008 
  (In thousands) 
COMMON STOCKHOLDER'S EQUITY:      
Common stock, $5 par value, 60,000,000 shares authorized,      
29,402,054 shares outstanding $147,010  $147,010 
Other paid-in capital  178,181   175,879 
Accumulated other comprehensive loss (Note 2(F))  (49,803)  (33,372)
Retained earnings (Note 12(A))  214,490   190,533 
Total  489,878   480,050 
         
NONCONTROLLING INTEREST  2,696   2,675 
         
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS (Note 12(C)):        
Secured notes-        
7.25% due 2020  300,000   - 
6.150% due 2037  300,000   300,000 
Total  600,000   300,000 
         
Capital lease obligations (Note 7)  3,492   80 
Net unamortized discount on debt  (2,827)  (420)
Long-term debt due within one year  (222)  (34)
Total long-term debt and other long-term obligations  600,443   299,626 
TOTAL CAPITALIZATION $1,093,017  $782,351 
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

169
THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

              Accumulated    
     Common Stock  Other  Other    
  Comprehensive  Number  Par  Paid-In  Comprehensive  Retained 
  Income  of Shares  Value  Capital  Income (Loss)  Earnings 
  (Dollars in thousands) 
                   
Balance, January 1, 2007     29,402,054  $147,010  $166,786  $(36,804) $204,423 
Earnings available to parent $91,239                   91,239 
Unrealized gain on investments, net                        
of $1,089,000 of income taxes  1,901               1,901     
Pension and other postretirement benefits, net                        
of $15,077,000 of income taxes (Note 3)  24,297               24,297     
Comprehensive income available to parent $117,437                     
Restricted stock units              53         
Stock-based compensation              2         
Consolidated tax benefit allocation              6,328         
Accounting for uncertainty in income taxes                        
cumulative effect adjustment                      (44)
Cash dividends declared on common stock                      (120,000)
Balance, December 31, 2007      29,402,054   147,010   173,169   (10,606)  175,618 
Earnings available to parent $74,915                   74,915 
Unrealized gain on investments, net                        
of $1,421,000 of income taxes  2,372               2,372     
Pension and other postretirement benefits, net                        
of $11,630,000 of income tax benefits (Note 3)  (25,138)              (25,138)    
Comprehensive income available to parent $52,149                     
Restricted stock units              47         
Stock-based compensation              1         
Consolidated tax benefit allocation              2,662         
Cash dividends declared on common stock                      (60,000)
Balance, December 31, 2008      29,402,054   147,010   175,879   (33,372)  190,533 
Earnings available to parent $23,957                   23,957 
Unrealized gain on investments, net                        
of $5,756,000 of income tax benefits  (9,425)              (9,425)    
Pension and other postretirement benefits, net                        
of $874,000 of income tax benefits (Note 3)  (7,006)              (7,006)    
Comprehensive income available to parent $7,526                     
Restricted stock units              71         
Consolidated tax benefit allocation              2,231         
Balance, December 31, 2009      29,402,054  $147,010  $178,181  $(49,803) $214,490 
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
Distribution MWH DeliveriesIncrease (Decrease)
Residential0.3 %
Commercial(1.9)%
Industrial2.4 %
Net Increase in Distribution Deliveries1.0 %

170
Distribution Revenues Increase
  (In millions)
Residential $11
Commercial 9
Industrial 8
Increase in Distribution Revenues $28
Retail generation revenues decreased $79 million in 2011 compared to 2010, primarily due to lower MWH sales from increased customer shopping and lower unit prices to all customer classes. The increases in shopping for residential, commercial and industrial customers were 13%, 9%, and 4%, respectively, in 2011 compared with 2010. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. TE defers the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings.


THE TOLEDO EDISON COMPANY114


Decreases in retail generation MWH sales and revenues in 2011 compared to 2010 are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(27.9)%
Commercial(39.7)%
Industrial(10.1)%
Decrease in Retail Generation Sales(20.5)%
Retail Generation Revenues Decrease
  (In millions)
Residential $(28)
Commercial (21)
Industrial (30)
Decrease in Retail Generation Revenues $(79)
Wholesale revenues increased $12 million in 2011 compared to 2010, primarily due to higher revenues from sales to NGC from TE’s leasehold interest in Beaver Valley Unit 2.
Operating Expenses
Total operating expenses decreased $37 million in 2011 compared to 2010. The following table presents changes from the prior year by expense category:
Operating Expenses - Changes Increase (Decrease)
  (In millions)
Purchased power costs $(76)
Other operating expenses 31
Pensions and OPEB mark-to-market adjustment 6
General taxes 2
Net Decrease in Operating Expenses $(37)
Purchased power costs decreased in 2011 compared to 2010, due to lower MWH purchases resulting from reduced generation sales requirements in 2011 coupled with lower unit costs. The increase in other operating costs in 2011 was primarily due to expenses associated with the 2011 nuclear refueling outage at the leased Beaver Valley Unit 2 and an Ohio Supreme Court decision rendered in the second quarter of 2011 favoring a large industrial customer, both of which were absent in 2010. Increased pensions and OPEB mark-to-market adjustment charges were due to higher net actuarial losses in 2011 as compared to 2010.
Other Expense
Other expense decreased slightly in 2011 compared to 2010, due to a decrease in miscellaneous expense partially offset by lower investment income. The change in miscellaneous expense was due to decreased expenses associated with the accounts receivable securitization with Centerior Funding Corp., which was terminated in 2011 Investment income decreased principally due to lower NDT investment income.
Interest Rate Risk
TE's exposure to fluctuations in market interest rates is reduced since all of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for TE’s investment portfolio and debt obligations.


CONSOLIDATED STATEMENTS OF CASH FLOWS115


Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income   $25
 $26
 $24
 $6
 $53
 $134
 $145
Average interest rate   7.7% 7.7% 7.7% 7.7% 4.6% 6.4%  
Liabilities:                
Long-term Debt:                
Fixed rate           $600
 $600
 $741
Average interest rate           6.7% 6.7%  
Equity Price Risk
NDT funds have been established to satisfy nuclear decommissioning obligations. Included in TE’s NDT are fixed income, equities and short-term investments carried at market values of approximately $53 million, $27 million and $3 million, respectively, as of December 31, 2011. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $3 million reduction in fair value as of December 31, 2011. TE recognizes in earnings the unrealized losses on available-for-sale securities held in their NDT as OTTI. A decline in the value of TE’s NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During 2011, approximately $1 million was contributed to TE's NDT to comply with requirements under certain sale-leaseback transactions in which TE continues as a lessee.
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. TE evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. TE may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. TE monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.


For the Years Ended December 31, 2009  2008  2007 
  (In thousands) 
CASH FLOWS FROM OPERATING ACTIVITIES:         
Net income $23,978  $74,927  $91,242 
Adjustments to reconcile net income to net cash from operating activities-            
Provision for depreciation  30,727   32,422   36,743 
Amortization of regulatory assets, net  37,820   94,104   41,684 
Purchased power cost recovery reconciliation  1,544   -   - 
Deferred rents and lease market valuation liability  (37,839)  (37,938)  265,981 
Deferred income taxes and investment tax credits, net  2,003   (16,869)  (26,318)
Accrued compensation and retirement benefits  3,489   1,483   5,276 
Accrued regulatory obligations  4,630   -   - 
Electric service prepayment programs  (1,458)  (11,181)  (10,907)
Pension trust contribution  (21,590)  -   (7,659)
Cash collateral from suppliers  2,794   -   - 
Lease assignment payment to associated company  (30,529)  -   - 
Gain on sales of investment securities held in trusts  (7,130)  (626)  (111)
Decrease (increase) in operating assets-            
Receivables  (18,872)  20,186   (64,489)
Prepayments and other current assets  (5,898)  (348)  (13)
Increase (decrease) in operating liabilities-            
Accounts payable  35,192   (164,397)  8,722 
Accrued taxes  (1,932)  (5,812)  (14,954)
Accrued interest  3,625   (17)  (1,350)
Other  374   (2,675)  5,296 
Net cash provided from (used for) operating activities  20,928   (16,741)  329,143 
             
CASH FLOWS FROM FINANCING ACTIVITIES:            
New Financing-            
Long-term debt  297,422   -   - 
Short-term borrowings, net  114,733   97,846   - 
Redemptions and Repayments-            
Long-term debt  (347)  (3,860)  (85,797)
Short-term borrowings, net  -   -   (153,567)
Dividend Payments-            
Common stock  (25,000)  (70,000)  (85,000)
Other  (351)  (131)  - 
Net cash provided from (used for) financing activities  386,457   23,855   (324,364)
             
CASH FLOWS FROM INVESTING ACTIVITIES:            
Property additions  (47,028)  (57,385)  (58,871)
Loan repayments from associated companies, net  63,711   43,098   40,306 
Redemption of lessor notes (Note 7)  18,330   11,959   14,847 
Sales of investment securities held in trusts  168,580   37,931   44,682 
Purchases of investment securities held in trusts  (170,996)  (40,960)  (47,853)
Other  (3,284)  (1,765)  2,110 
Net cash provided from (used for) investing activities  29,313   (7,122)  (4,779)
             
Net change in cash and cash equivalents  436,698   (8)  - 
Cash and cash equivalents at beginning of year  14   22   22 
Cash and cash equivalents at end of year $436,712  $14  $22 
             
SUPPLEMENTAL CASH FLOW INFORMATION:            
Cash Paid During the Year-            
Interest (net of amounts capitalized) $32,353  $22,203  $33,841 
Income taxes $1,350  $62,879  $73,845 
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

116
171


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 in 3,200 square miles of northern, western and east central New Jersey. The area it serves has a population of approximately 2.7 million. JCP&L also has an ownership interest in a hydroelectric generating facility. In addition, JCP&L also procures generation services for franchise customers electing to retain them 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: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Contractual Obligations, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
Results of Operations
Net income decreased by $39 million in 2011 compared to 2010. The decrease was primarily due to lower revenues, partially offset by reductions in purchased power costs and amortization of regulatory assets.
Revenues
Revenues decreased by $532 million, or 18%, in 2011 compared to 2010. The decrease in revenues was due to lower distribution, retail generation and wholesale generation revenues, partially offset by an increase in other revenues.
Distribution revenues decreased by $187 million in 2011, compared to 2010, primarily due to an NJBPU-approved rate adjustment that became effective March 1, 2011 for all customer classes, and lower MWH deliveries. The lower MWH deliveries to residential customers were influenced by decreased weather-related usage in 2011. Lower distribution deliveries to commercial and industrial customers reflected the impact of economic conditions in JCP&L's service territory.
Decreases in distribution MWH deliveries and revenues in 2011 compared to 2010 are summarized in the following tables:
Distribution MWH DeliveriesDecrease
Residential(3.0)%
Commercial(2.9)%
Industrial(3.0)%
Decrease in Distribution Deliveries(2.9)%
Distribution Revenues Decrease
  (In millions)
Residential $(90)
Commercial (79)
Industrial (18)
Decrease in Distribution Revenues $(187)

Retail generation revenues decreased by $301 million due to lower generation MWH sales in all customer classes primarily due to an increase in customer shopping. The increases in shopping for residential, commercial and industrial customers were 10%, 9% and 5%, respectively, in 2011 compared with 2010. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. JCP&L defers the difference between retail generation revenues and purchased power costs, resulting in no material effect to earnings.


117


Decreases in retail generation MWH sales and revenues in 2011, compared to 2010, are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(13.0)%
Commercial(23.0)%
Industrial(29.0)%
Decrease in Retail Generation Sales(16.3)%
Retail Generation Revenues Decrease
  (In millions)
Residential $(181)
Commercial (108)
Industrial (12)
Decrease in Retail Generation Revenues $(301)

Wholesale generation revenues decreased by $54 million in 2011, compared to 2010, due to a decrease in PJM spot market energy sales.
Other revenues increased by $10 million in 2011, compared to 2010, primarily due to increases in PJM network transmission revenues and transition bond revenues from increased rates.
Operating Expenses
Total operating expenses decreased by $461 million in 2011 compared to 2010. The following table presents changes from the prior year by expense category:
Operating Expenses - Changes Increase (Decrease)
  (In millions)
Purchased power costs $(354)
Other operating expenses 48
Pensions and OPEB mark-to-market adjustment 34
Provision for depreciation 22
Amortization of regulatory assets, net (213)
General taxes 2
Net Decrease in Operating Expenses $(461)

Purchased power costs decreased by $354 million in 2011 due to lower requirements from reduced retail generation sales. Other operating expenses increased by $48 million in 2011 principally from storm restoration maintenance costs. Increased pensions and OPEB mark-to-market adjustment changes were due to higher net actuarial losses in 2011 as compared to 2010. Amortization of regulatory assets, net, decreased by $213 million due to reduced cost recovery under the NJBPU-approved NUG tariffs that became effective March 1, 2011 and higher deferred storm restoration costs, partially offset by a charge for nonrecoverable NUG costs.
Market Risk Information
JCP&L uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.
Commodity Price Risk
JCP&L is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas and energy transmission. FirstEnergy's Risk Policy 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 practice. JCP&L uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.
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, JCP&L relies on model-based information. The model provides estimates of future


118


regional prices for electricity and an estimate of related price volatility. JCP&L uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making (see Note 9, Fair Value Measurements of the Combined Notes to the Consolidated Financial Statements). Sources of information for the valuation of commodity derivative contract assets and liabilities as of December 31, 2011, are summarized by year in the following table:
Source of Information-
Fair Value by Contract Year
 2012 2013 2014 2015 2016 Thereafter Total
  (In millions)
Prices actively quoted(1)
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Other external sources(2)
 (52) (43) (36) (14) —
 —
 (145)
Prices based on models —
 —
 —
 —
 1
 1
 2
Total(3)
 $(52) $(43) $(36) $(14) $1
 $1
 $(143)
(1)
Represents exchange traded New York Mercantile Exchange futures and options.
(2)
Primarily represents contracts based on broker and IntercontinentalExchange quotes.
(3)
Includes $(143) million in non-hedge commodity derivative contracts that are related to NUG contracts. NUG contracts are subject to regulatory accounting and do not materially impact earnings.
JCP&L performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. Based on derivative contracts held as of December 31, 2011, an adverse 10% change in commodity prices would not have a material effect on JCP&L’s net income for the next 12 months.
Interest Rate Risk
JCP&L’s exposure to fluctuations in market interest rates is reduced since all of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for JCP&L’s investment portfolio and debt obligations.
Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income           $363
 $363
 $363
Average interest rate           5.2% 5.2%  
Liabilities:                
Long-term Debt:                
Fixed rate $34
 $36
 $38
 $41
 $343
 $1,285
 $1,777
 $2,080
Average interest rate 5.7% 5.7% 5.9% 6.0% 5.7% 6.2% 6.1%  
Equity Price Risk
NDT funds have been established to satisfy nuclear decommissioning obligations. Included in JCP&L’s NDT are fixed income, equities and short-term investments carried at market values of approximately $147 million, $30 million and $14 million, respectively, as of December 31, 2011, excluding $2 million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $3 million reduction in fair value as of December 31, 2011. JCP&L's NDT is 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. A decline in the value of JCP&L's NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During 2011, approximately $1 million was contributed to JCP&L's NDT to comply with regulatory requirements.
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. JCP&L evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. JCP&L may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. JCP&L monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.


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METROPOLITAN EDISON COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
Met-Ed is a wholly owned electric utility subsidiary of FirstEnergy. Met-Ed provides regulated electric transmission and distribution services in 3,300 square miles of eastern and south central Pennsylvania. The area it serves has a population of approximately 1.2 million. Met-Ed also procures generation service for those franchise customers who have elected to retain them as their power supplier. Met-Ed procures power under its DSP, in which full requirements products (energy, capacity, ancillary services, and applicable transmission services) are procured through descending clock auctions.
For additional information with respect to Met-Ed, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Contractual Obligations, Off-Balance Sheet Arrangements, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
On January 25, 2012, Met-Ed filed a Form 15 with the SEC to deregister its securities and suspend its obligation to file periodic reports under the Securities Exchange Act of 1934, as amended, except that the registrant has filed this Annual Report on Form 10-K for the year ended December 31, 2011. This Annual Report on Form 10-K will be the last filing made by Met-Ed with the SEC under the Exchange Act.
Results of Operations
Net income increased by $8 million in 2011 compared to 2010. The increase was primarily due to decreased purchased power costs, other operating expenses and amortization of net regulatory assets partially offset by decreased revenues.
Revenues
Revenue decreased $606 million, or 33%, in 2011 compared to 2010, reflecting lower distribution, retail generation, wholesale generation and transmission revenues.
Distribution revenues decreased $336 million in 2011 compared to 2010, primarily due to lower rates resulting from the DSP that began in 2011 that eliminated the transmission component from the distribution rates. The lower MWH deliveries to residential and commercial customers were influenced by decreased weather-related usage in 2011. In the industrial sector, MWH deliveries increased primarily as a result of recovering economic conditions in Met-Ed's service territory.
Changes in distribution MWH deliveries and revenues in 2011 compared to 2010 are summarized in the following tables:
Distribution MWH DeliveriesIncrease (Decrease)
Residential(1.4)%
Commercial(2.0)%
Industrial2.2 %
Net Decrease in Distribution Deliveries(0.2)%
Distribution Revenues Decrease
  (In millions)
Residential $(133)
Commercial (90)
Industrial (113)
Decrease in Distribution Revenues $(336)
In 2011, retail generation revenues decreased $52 million due to lower MWH sales to all customer classes resulting from increased customer shopping. The impact of increased customer shopping is partially offset by higher generation rates that reflect the inclusion of transmission services under the DSP, effective January 1, 2011, for all customer classes. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. In 2011, Met-Ed began deferring the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings.


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Changes in retail generation MWH sales and revenues in 2011 compared to 2010 are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(3.8)%
Commercial(49.1)%
Industrial(91.8)%
Net Decrease in Retail Generation Sales(45.7)%
Retail Generation Revenues Increase (Decrease)
  (In millions)
Residential $166
Commercial (24)
Industrial (194)
Net Decrease in Retail Generation Revenues $(52)
Wholesale revenues decreased $210 million in 2011 compared to 2010, primarily reflecting lower RPM revenues for Met-Ed in the PJM market.
Transmission revenues decreased $9 million in 2011 compared to 2010 primarily due to the termination of Met-Ed’s TSC rates effective January 1, 2011. Met-Ed deferred the difference between transmission revenues and transmission costs incurred, resulting in no material effect to earnings in the period.
Operating Expenses
Total operating expenses decreased $608 million in 2011 compared to 2010. The following table presents changes from the prior year by expense category:
Operating Expenses - Changes Increase (Decrease)
  (In millions)
Purchased power costs $(328)
Other operating costs (230)
Pensions and OPEB mark-to-market adjustment 26
Provision for depreciation 5
Amortization of regulatory assets, net (68)
General taxes (13)
Net Decrease in Operating Expenses $(608)
Purchased power costs decreased $328 million in 2011 compared to 2010 due to a decrease in MWH purchased to source generation sales requirements, partially offset by higher unit costs. Decreased power purchased from affiliates reflects the increase in customer shopping described above and the termination of Met-Ed's partial requirements PSA with FES at the end of 2010. Other operating costs decreased $230 million in 2011 compared to 2010 due to lower transmission congestion and transmission loss expenses that are now included in the cost of purchased power (see reference to deferral accounting above), partially offset by increased costs for energy efficiency programs. Increased pensions and OPEB mark-to-market adjustment changes were due to higher net actuarial losses in 2011 as compared to 2010. The amortization of regulatory assets decreased $68 million in 2011 compared to 2010 primarily due to the termination of transmission and transition tariff riders at the end of 2010. General taxes decreased by $13 million in 2011 primarily due to lower gross receipts taxes.
Other Expense
Interest income decreased by $3 million in 2011 compared to 2010 primarily due to reduced CTC stranded asset balances.
Market Risk Information
Met-Ed uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.


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Commodity Price Risk
Met-Ed is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas and energy transmission. FirstEnergy's Risk Policy 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 practice. Met-Ed uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.
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, Met-Ed relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Met-Ed uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making (see Note 9, Fair Value Measurements of the Combined Notes to the Consolidated Financial Statements). Sources of information for the valuation of commodity derivative contract assets and liabilities as of December 31, 2011, are summarized by year in the following table:
Source of Information-
Fair Value by Contract Year
 2012 2013 2014 2015 2016 Thereafter Total
  (In millions)
Prices actively quoted(1)
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Other external sources(2)
 (62) (7) (6) (5) —
 —
 (80)
Prices based on models —
 —
 —
 —
 8
 42
 50
Total(3)
 $(62) $(7) $(6) $(5) $8
 $42
 $(30)
(1)
Represents exchange traded New York Mercantile Exchange futures and options.
(2)
Primarily represents contracts based on broker and IntercontinentalExchange quotes.
(3)
Includes $(30) million in non-hedge commodity derivative contracts that are related to NUG contracts. NUG contracts are subject to regulatory accounting and do not materially impact earnings.
Met-Ed performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. Based on derivative contracts held as of December 31, 2011, an adverse 10% change in commodity prices would not have a material effect on Met-Ed’s net income for the next 12 months.
Interest Rate Risk
Met-Ed’s exposure to fluctuations in market interest rates is reduced since a significant portion of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for Met-Ed’s investment portfolio and debt obligations.
Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income           $234
 $234
 $234
Average interest rate           3.3% 3.3%  
Liabilities:                
Long-term Debt:                
Fixed rate   $150
 $250
     $300
 $700
 $796
Average interest rate   5.0% 4.9%     7.7% 6.1%  
Variable rate           $29
 $29
 $29
Average interest rate           0.1% 0.1%  
Equity Price Risk
NDT funds have been established to satisfy nuclear decommissioning obligations. Included in Met-Ed’s NDT are fixed income, equities and short-term investments carried at market values of approximately $234 million, $51 million and $23 million, respectively, as of December 31, 2011, excluding $2 million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $5 million reduction in fair value as of December 31, 2011. Met-Ed's NDT is 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. A decline


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in the value of Met-Ed's NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements.
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. Met-Ed evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. Met-Ed may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. Met-Ed monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.


123


PENNSYLVANIA ELECTRIC COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec provides regulated electric transmission and distribution services in 17,600 square miles of western, northern and south central Pennsylvania. The area it serves has a population of approximately 1.3 million. Penelec, as lessee of the property of its subsidiary, The Waverly Electric Light & Power Company, serves customers in the Waverly, New York vicinity. Penelec also procures generation service for those franchise customers who have elected to retain them as their power supplier. Penelec procures power under its DSP, in which full requirements products (energy, capacity, ancillary services and applicable transmission services) are procured through descending clock auctions.
For additional information with respect to Penelec, 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: Strategy and Outlook, Risks and Challenges, Capital Resources and Liquidity, Contractual Obligations, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
On January 25, 2012, Penelec filed a Form 15 with the SEC to deregister its securities and suspend its obligation to file periodic reports under the Securities Exchange Act of 1934, as amended, except that the registrant has filed this Annual Report on Form 10-K for the year ended December 31, 2011. This Annual Report on Form 10-K will be the last filing made by Penelec with the SEC under the Exchange Act.
Results of Operations
Net income was unchanged in 2011, compared to 2010, due to lower purchased power costs, other operating expenses and income taxes, partially offset by lower revenues and higher amortization of regulatory assets.
Revenues
Revenues decreased by $459 million, or 30%, in 2011 compared to 2010. The decrease in revenue was primarily due to lower distribution, retail generation, wholesale generation and transmission revenues.
Distribution revenues decreased by $93 million in 2011, compared to 2010, primarily due to lower rates resulting from the DSP, which eliminated the transmission component from the distribution rate beginning in 2011, partially offset by a PPUC-approved rate adjustment for NUG costs. Lower MWH deliveries to residential and commercial customers reflected decreased weather-related usage compared to 2010. Higher MWH deliveries to industrial customers were primarily due to recovering economic conditions in Penelec’s service territory, compared to 2010.
Changes in distribution MWH deliveries and revenues in 2011, compared to 2010, are summarized in the following tables:
Distribution MWH Deliveries
Increase
(Decrease)
Residential(2.2)%
Commercial(3.7)%
Industrial4.5 %
Net Decrease in Distribution Deliveries0.1 %
Distribution Revenues Decrease
  (In millions)
Residential $(35)
Commercial (31)
Industrial (27)
Decrease in Distribution Revenues $(93)

Retail generation revenues decreased by $218 million in 2011, compared to 2010, due to lower MWH sales in all customer classes resulting from increased customer shopping. The impact of customer shopping was partially offset by higher generation rates that reflect the inclusion of transmission services under the DSP, effective January 1, 2011, for all customer classes. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. In 2011, Penelec began deferring the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings.


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Changes in retail generation MWH sales and revenues in 2011, compared to 2010, are summarized in the following tables:
Retail Generation MWH SalesDecrease
Residential(8.5)%
Commercial(53.6)%
Industrial(92.5)%
Decrease in Retail Generation Sales(53.1)%
Retail Generation Revenues 
Increase
(Decrease)
  (In millions)
Residential $87
Commercial (78)
Industrial (227)
Net Decrease in Retail Generation Revenues $(218)

Wholesale generation revenues decreased by $205 million in 2011, compared to 2010, reflecting lower RPM revenues for Penelec in the PJM market.
Transmission revenues decreased by $7 million in 2011, compared to 2010, primarily due to the termination of Penelec’s TSC rates effective January 1, 2011. Penelec deferred the difference between transmission revenues and transmission costs incurred, resulting in no material effect to earnings for the period.
Operating Expenses

Total operating expenses decreased by $446 million in 2011 as compared to 2010. The following table presents changes from the prior year by expense category:
Operating Expenses - Changes Increase (Decrease)
  (In millions)
Purchased power costs (467)
Other operating costs (99)
Pensions and OPEB mark-to-market adjustment 33
Provision for depreciation (3)
Amortization of regulatory assets, net 97
General taxes (7)
Net Decrease in Operating Expenses $(446)

Purchased power costs decreased by $467 million in 2011, compared to 2010, due to a decrease in MWH purchased to source generation sales requirements. Decreased power purchased from affiliates resulted from reduced requirements due to the increase in customer shopping described above and the termination of Penelec's partial requirements PSA with FES at the end of 2010. Other operating costs decreased by $99 million in 2011 due to lower transmission congestion and transmission loss expenses that are now included in the cost of purchased power (see reference to deferral accounting above). Increased pensions and OPEB mark-to-market adjustment charges were due to higher net actuarial losses in 2011 as compared to 2010. The amortization of regulatory assets increased by $97 million in 2011 primarily due to reduced NUG deferrals as a result of the PPUC-approved increase in Penelec’s NUG cost recovery rider in January 2011.
Other Expenses
Other expenses decreased by $3 million in 2011, compared to 2010, due to lower income from jobbing and contracting work and lower capitalized interest.
Market Risk Information
Penelec uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.



125


Commodity Price Risk
Penelec is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas and energy transmission. FirstEnergy's Risk Policy 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 practice. Penelec uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.
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, Penelec relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Penelec uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making (see Note 9, Fair Value Measurements of the Combined Notes to the Consolidated Financial Statements). Sources of information for the valuation of commodity derivative contract assets and liabilities as of December 31, 2011, are summarized by year in the following table:
Source of Information-
Fair Value by Contract Year
 2012 2013 2014 2015 2016 Thereafter Total
  (In millions)
Prices actively quoted(1)
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Other external sources(2)
 (85) (12) (10) (11) —
 —
 (118)
Prices based on models —
 —
 —
 —
 1
 (3) (2)
Total(3)
 $(85) $(12) $(10) $(11) $1
 $(3) $(120)
(1)
Represents exchange traded New York Mercantile Exchange futures and options.
(2)
Primarily represents contracts based on broker and IntercontinentalExchange quotes.
(3)
Includes $(120) million in non-hedge commodity derivative contracts that are related to NUG contracts. NUG contracts are subject to regulatory accounting and do not materially impact earnings.
Penelec performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. Based on derivative contracts held as of December 31, 2011, an adverse 10% change in commodity prices would not have a material effect on Penelec’s net income for the next 12 months.
Interest Rate Risk
Penelec’s exposure to fluctuations in market interest rates is reduced since a significant portion of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for Penelec’s investment portfolio and debt obligations.
Comparison of Carrying Value to Fair Value
Year of Maturity 2012 2013 2014 2015 2016 There-after Total Fair Value
  (In millions)
Assets:                
Investments Other Than Cash and Cash Equivalents:                
Fixed Income           $195
 $195
 $195
Average interest rate           3.8% 3.8%  
Liabilities:                
Long-term Debt:                
Fixed rate     $150
     $925
 $1,075
 $1,206
Average interest rate     5.1%     5.9% 5.8%  
Variable rate           $45
 $45
 $45
Average interest rate           0.1% 0.1%  
Equity Price Risk
NDT funds have been established to satisfy nuclear decommissioning obligations. Included in Penelec’s NDT are fixed income, equities and short-term investments carried at market values of approximately $106 million, $26 million and $33 million, respectively, as of December 31, 2011, excluding $1 million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $3 million reduction in fair value as of December 31, 2011. Penelec's NDT is 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. A decline


126


in the value of Penelec's NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements.
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. Penelec evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. Penelec may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. Penelec monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.


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ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by ITEM 7A relating to market risk is set forth in ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.


128


ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
MANAGEMENT REPORTS
Management’s Responsibility for Financial Statements
The consolidated financial statements of FirstEnergy Corp. (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2011 consolidated financial statements as stated in their audit report included herein.
The Company’s internal auditors, who are responsible to the Audit Committee of the Company’s Board of Directors, review the results and performance of operating units within the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.
The Company’s Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm’s report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm’s independence. The Committee also reviews management’s programs to monitor compliance with the Company’s policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held eight meetings in 2011.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control — Integrated Framework, management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting under the supervision of the Chief Executive Officer and the Chief Financial Officer. Based on that evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2011. The effectiveness of the Company’s internal control over financial reporting, as of December 31, 2011, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.


129


MANAGEMENT REPORTS
Management’s Responsibility for Financial Statements
The consolidated financial statements of FirstEnergy Solutions Corp. (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2011 consolidated financial statements as stated in their audit report included herein.
FirstEnergy Corp.’s internal auditors, who are responsible to the Audit Committee of FirstEnergy’s Board of Directors, review the results and performance of the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.
FirstEnergy’s Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm’s report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm’s independence. The Committee also reviews management’s programs to monitor compliance with the Company’s policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held eight meetings in 2011.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control — Integrated Framework, management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting under the supervision of the Chief Executive Officer and the Chief Financial Officer. Based on that evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2011.


130


MANAGEMENT REPORTS
Management’s Responsibility for Financial Statements
The consolidated financial statements of Ohio Edison Company (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2011 consolidated financial statements as stated in their audit report included herein.
FirstEnergy Corp.’s internal auditors, who are responsible to the Audit Committee of FirstEnergy’s Board of Directors, review the results and performance of the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.
FirstEnergy’s Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm’s report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm’s independence. The Committee also reviews management’s programs to monitor compliance with the Company’s policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held eight meetings in 2011.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control — Integrated Framework, management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting under the supervision of the Chief Executive Officer and the Chief Financial Officer. Based on that evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2011.


131


MANAGEMENT REPORTS
Management’s Responsibility for Financial Statements
The consolidated financial statements of The Cleveland Electric Illuminating Company (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2011 consolidated financial statements as stated in their audit report included herein.
FirstEnergy Corp.’s internal auditors, who are responsible to the Audit Committee of FirstEnergy’s Board of Directors, review the results and performance of the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.
FirstEnergy’s Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm’s report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm’s independence. The Committee also reviews management’s programs to monitor compliance with the Company’s policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held eight meetings in 2011.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control — Integrated Framework, management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting under the supervision of the Chief Executive Officer and the Chief Financial Officer. Based on that evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2011.


132


MANAGEMENT REPORTS
Management’s Responsibility for Financial Statements
The consolidated financial statements of The Toledo Edison Company (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2011 consolidated financial statements as stated in their audit report included herein.
FirstEnergy Corp.’s internal auditors, who are responsible to the Audit Committee of FirstEnergy’s Board of Directors, review the results and performance of the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.
FirstEnergy’s Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm’s report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm’s independence. The Committee also reviews management’s programs to monitor compliance with the Company’s policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held eight meetings in 2011.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control — Integrated Framework, management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting under the supervision of the Chief Executive Officer and the Chief Financial Officer. Based on that evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2011.


133


MANAGEMENT REPORTS
Management’s Responsibility for Financial Statements
The consolidated financial statements of Jersey Central Power & Light Company (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2011 consolidated financial statements as stated in their audit report included herein.
FirstEnergy Corp.’s internal auditors, who are responsible to the Audit Committee of FirstEnergy’s Board of Directors, review the results and performance of the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.
FirstEnergy’s Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm’s report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm’s independence. The Committee also reviews management’s programs to monitor compliance with the Company’s policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held eight meetings in 2011.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control — Integrated Framework, management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting under the supervision of the Chief Executive Officer and the Chief Financial Officer. Based on that evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2011.


134


MANAGEMENT REPORTS
Management’s Responsibility for Financial Statements
The consolidated financial statements of Metropolitan Edison Company (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2011 consolidated financial statements as stated in their audit report included herein.
FirstEnergy Corp.’s internal auditors, who are responsible to the Audit Committee of FirstEnergy’s Board of Directors, review the results and performance of the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.
FirstEnergy’s Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm’s report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm’s independence. The Committee also reviews management’s programs to monitor compliance with the Company’s policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held eight meetings in 2011.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control — Integrated Framework, management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting under the supervision of the Chief Executive Officer and the Chief Financial Officer. Based on that evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2011.


135


MANAGEMENT REPORTS
Management’s Responsibility for Financial Statements
The consolidated financial statements of Pennsylvania Electric Company (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2011 consolidated financial statements as stated in their audit report included herein.
FirstEnergy Corp.’s internal auditors, who are responsible to the Audit Committee of FirstEnergy’s Board of Directors, review the results and performance of the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.
FirstEnergy’s Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm’s report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm’s independence. The Committee also reviews management’s programs to monitor compliance with the Company’s policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held eight meetings in 2011.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control — Integrated Framework, management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting under the supervision of the Chief Executive Officer and the Chief Financial Officer. Based on that evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2011.


136


Report of Independent Registered Public Accounting Firm


Tothe Stockholders and Board of Directors of FirstEnergy Corp.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, common stockholders' equity, and cash flows present fairly, in all material respects, the financial position of FirstEnergy Corp. and its subsidiariesatDecember 31, 2011and 2010, and the results of their operations and their cash flows for each of the three years in the period endedDecember 31, 2011in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2)presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidatedfinancial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 1to the consolidated financial statements, in 2011 the Company changed its method of accounting for pension and other postemployment benefit plans. All periods have been retroactively restated for this accounting change.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.


/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Cleveland, Ohio
February 28, 2012


137


Report of Independent Registered Public Accounting Firm

Tothe Stockholder and Board of
Directors of FirstEnergy Solutions Corp.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, common stockholder's equity, and cash flows present fairly, in all material respects, the financial position of FirstEnergy Solutions Corp. and its subsidiaries at December 31, 2011 and 2010, and the results oftheir operations and their cash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2)presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidatedfinancial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, in 2011 the Company changed its method of accounting for pension and other postemployment benefit plans. All periods have been retroactively restated for this accounting change.


/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Cleveland, Ohio
February 28, 2012


138


Report of Independent Registered Public Accounting Firm

Tothe Stockholder and Board of
Directors of Ohio Edison Company:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, common stockholder's equity, and cash flows present fairly, in all material respects, the financial position of Ohio Edison Company and its subsidiaries at December 31, 2011 and 2010, and the results of their operations and theircash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2)presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, in 2011 the Company changed its method of accounting for pension and other postemployment benefit plans. All periods have been retroactively restated for this accounting change.


/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Cleveland, Ohio
February 28, 2012


139


Report of Independent Registered Public Accounting Firm

Tothe Stockholder and Board of Directors of
The Cleveland Electric Illuminating Company:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, common stockholder's equity, and cash flows present fairly, in all material respects, the financial position of The Cleveland Electric Illuminating Company and its subsidiaries at December 31, 2011 and 2010, and the results of theiroperations and theircash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2)presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, in 2011 the Company changed its method of accounting for pension and other postemployment benefit plans. All periods have been retroactively restated for this accounting change.


/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Cleveland, Ohio
February 28, 2012


140


Report of Independent Registered Public Accounting Firm

Tothe Stockholder and Board of
Directors of The Toledo Edison Company:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, common stockholder's equity, and cash flows present fairly, in all material respects, the financial position of The Toledo Edison Company and its subsidiary at December 31, 2011 and 2010, and the results oftheir operations and their cash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2)presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, in 2011 the Company changed its method of accounting for pension and other postemployment benefit plans. All periods have been retroactively restated for this accounting change.


/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Cleveland, Ohio
February 28, 2012


141


Report of Independent Registered Public Accounting Firm

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

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, common stockholder's equity, and cash flows present fairly, in all material respects, the financial position of Jersey Central Power & Light Company and its subsidiaries at December 31, 2011 and 2010, and the results oftheir operations and theircash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2)presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidatedfinancial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, in 2011 the Company changed its method of accounting for pension and other postemployment benefit plans. All periods have been retroactively restated for this accounting change.


/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Cleveland, Ohio
February 28, 2012


142


Report of Independent Registered Public Accounting Firm

Tothe Stockholder and Board of
Directors of Metropolitan Edison Company:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, common stockholder's equity, and cash flows present fairly, in all material respects, the financial position of Metropolitan Edison Company and its subsidiaries at December 31, 2011 and 2010, and the results oftheir operations and theircash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2)presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidatedfinancial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, in 2011 the Company changed its method of accounting for pension and other postemployment benefit plans. All periods have been retroactively restated for this accounting change.


/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Cleveland, Ohio
February 28, 2012


143


Report of Independent Registered Public Accounting Firm

Tothe Stockholder and Board of
Directors of Pennsylvania Electric Company:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, common stockholder's equity, and cash flows present fairly, in all material respects, the financial position of Pennsylvania Electric Company and its subsidiaries at December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, in 2011 the Company changed its method of accounting for pension and other postemployment benefit plans. All periods have been retroactively restated for this accounting change.


/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Cleveland, Ohio
February 28, 2012


144


FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
  For the Years Ended December 31,
(In millions, except per share amounts) 2011 2010 2009
       
REVENUES:      
Electric utilities $10,396
 $9,815
 $11,139
Unregulated businesses 5,862
 3,524
 1,834
Total revenues* 16,258
 13,339
 12,973
       
OPERATING EXPENSES:      
Fuel 2,317
 1,432
 1,153
Purchased power 4,986
 4,624
 4,730
Other operating expenses 3,909
 2,696
 2,551
Pensions and OPEB mark-to-market adjustment 507
 190
 321
Provision for depreciation 1,121
 768
 757
Amortization of regulatory assets, net 329
 722
 1,019
General taxes 978
 776
 753
Impairment of long-lived assets 413
 388
 6
Total operating expenses 14,560
 11,596
 11,290
       
OPERATING INCOME 1,698
 1,743
 1,683
       
OTHER INCOME (EXPENSE):      
Gain on partial sale of Signal Peak 569
 —
 —
Investment income 114
 117
 204
Interest expense (1,008) (845) (978)
Capitalized interest 70
 165
 131
Total other expense (255) (563) (643)
       
INCOME BEFORE INCOME TAXES 1,443
 1,180
 1,040
       
INCOME TAXES 574
 462
 184
       
NET INCOME 869
 718
 856
       
Loss attributable to noncontrolling interest (16) (24) (16)
       
EARNINGS AVAILABLE TO FIRSTENERGY CORP. $885
 $742
 $872
       
EARNINGS PER SHARE OF COMMON STOCK:      
Basic $2.22
 $2.44
 $2.87
Diluted $2.21
 $2.42
 $2.85
       
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING      
Basic 399
 304
 304
Diluted 401
 305
 306
* Includes $486 million, $428 million and $395 million of excise tax collections in 2011, 2010 and 2009, respectively.
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


For the Years Ended December 31, 2009  2008  2007 
  (In thousands) 
          
REVENUES (Note 18):         
Electric sales $2,943,590  $3,420,772  $3,191,999 
Excise tax collections  49,097   51,481   51,848 
Total revenues  2,992,687   3,472,253   3,243,847 
             
EXPENSES (Note 18):            
Purchased power from non-affiliates  1,782,435   2,206,251   1,957,975 
Other operating costs  309,791   302,894   325,814 
Provision for depreciation  102,912   96,482   85,459 
Amortization of regulatory assets  344,158   364,816   388,581 
General taxes  63,078   67,340   66,225 
Total expenses  2,602,374   3,037,783   2,824,054 
             
OPERATING INCOME  390,313   434,470   419,793 
             
OTHER INCOME (EXPENSE):            
Miscellaneous income (expense)  5,272   (1,037)  8,570 
Interest expense (Note 18)  (116,851)  (99,459)  (96,988)
Capitalized interest  543   1,245   3,789 
Total other expense  (111,036)  (99,251)  (84,629)
             
INCOME BEFORE INCOME TAXES  279,277   335,219   335,164 
             
INCOME TAXES  108,778   148,231   149,056 
             
NET INCOME $170,499  $186,988  $186,108 
145


FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
  For the Years Ended December 31,
(In millions) 2011 2010 2009
       
NET INCOME $869
 $718
 $856
       
OTHER COMPREHENSIVE INCOME (LOSS):      
Pensions and OPEB prior service costs (90) (220) 275
Unrealized gain on derivative hedges 23
 36
 51
Change in unrealized gain on available-for-sale securities 19
 8
 (74)
Other comprehensive income (loss) (48) (176) 252
Income taxes (benefits) on other comprehensive income (loss) (49) (74) 128
Other comprehensive income (loss), net of tax 1
 (102) 124
       
COMPREHENSIVE INCOME 870
 616
 980
       
COMPREHENSIVE LOSS ATTRIBUTABLE TO NONCONTROLLING INTEREST (16) (24) (16)
       
COMPREHENSIVE INCOME AVAILABLE TO FIRSTENERGY CORP. $886
 $640
 $996
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

172



146


FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
  As of December 31,
(In millions, except share amounts) 2011 2010
ASSETS    
CURRENT ASSETS:    
Cash and cash equivalents $202
 $1,019
Receivables-    
Customers, net of allowance for uncollectible accounts of $37 in 2011 and $36 in 2010 1,525
 1,392
Other, net of allowance for uncollectible accounts of $3 in 2011 and $8 in 2010 269
 176
Materials and supplies, at average cost 811
 638
Prepaid taxes 191
 199
Derivatives 235
 182
Other 122
 92
  3,355
 3,698
PROPERTY, PLANT AND EQUIPMENT:    
In service 40,122
 30,276
Less — Accumulated provision for depreciation 11,839
 11,283
  28,283
 18,993
Construction work in progress 2,054
 1,517
  30,337
 20,510
INVESTMENTS:    
Nuclear plant decommissioning trusts 2,112
 1,973
Investments in lease obligation bonds 402
 476
Other 1,008
 553
  3,522
 3,002
DEFERRED CHARGES AND OTHER ASSETS:    
Goodwill 6,441
 5,575
Regulatory assets 2,030
 1,830
Other 1,641
 916
  10,112
 8,321
  $47,326
 $35,531
LIABILITIES AND CAPITALIZATION    
CURRENT LIABILITIES:    
Currently payable long-term debt $1,621
 $1,486
Short-term borrowings —
 700
Accounts payable 1,174
 872
Accrued taxes 558
 332
Accrued compensation and benefits 384
 315
Derivatives 218
 266
Other 900
 733
  4,855
 4,704
CAPITALIZATION:    
Common stockholders’ equity-    
Common stock, $0.10 par value, authorized 490,000,000 and 375,000,000 shares, respectively- 418,216,437 and 304,835,407 shares outstanding, respectively 42
 31
Other paid-in capital 9,765
 5,444
Accumulated other comprehensive income 426
 425
Retained earnings 3,047
 3,084
Total common stockholders’ equity 13,280
 8,984
Noncontrolling interest 19
 (32)
Total equity 13,299
 8,952
Long-term debt and other long-term obligations 15,716
 12,579
  29,015
 21,531
NONCURRENT LIABILITIES:    
Accumulated deferred income taxes 5,670
 3,160
Retirement benefits 2,823
 1,868
Asset retirement obligations 1,497
 1,407
Deferred gain on sale and leaseback transaction 925
 959
Adverse power contract liability 469
 466
Other 2,072
 1,436
  13,456
 9,296
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Notes 6 and 16) 
 
  $47,326
 $35,531
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


147


FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
  Common Stock Other Paid-In Capital Accumulated Other Comprehensive Income Retained Earnings
(In millions, except share amounts) Number of Shares Par Value   
Balance, January 1, 2009 304,835,407
 $31
 $5,473
 $403
 $2,810
Earnings available to FirstEnergy Corp.         872
Change in unrealized loss on derivative hedges, net of $24 million of income taxes       27
  
Change in unrealized gain on investments, net of $31 million of income tax benefits       (43)  
Pensions and OPEB, net of $135 million of income taxes (Note 3)       140
  
Stock options exercised     (3)    
Restricted stock units     7
    
Stock-based compensation     1
    
Acquisition adjustment of non-controlling interest (Note 8)     (30)    
Cash dividends declared on common stock         (670)
Balance, December 31, 2009 304,835,407
 31
 5,448
 527
 3,012
Earnings available to FirstEnergy Corp.         742
Change in unrealized loss on derivative hedges, net of $14 million of income taxes       22
  
Change in unrealized gain on investments, net of $3 million of income taxes       5
  
Pensions and OPEB, net of $91 million of income tax benefits (Note 3)       (129)  
Stock options exercised     (2)    
Restricted stock units     (3)    
Stock-based compensation     1
    
Cash dividends declared on common stock         (670)
Balance, December 31, 2010 304,835,407
 31
 5,444
 425
 3,084
Earnings available to FirstEnergy Corp.         885
Change in unrealized loss on derivative hedges, net of $8 million of income taxes       15
  
Change in unrealized gain on investments, net of $7 million of income taxes       12
  
Pensions and OPEB, net of $64 million of income tax benefits (Note 3)       (26)  
Stock options exercised     5
    
Restricted stock units     (2)    
Stock-based compensation     2
    
Allegheny merger 113,381,030
 11
 4,316
    
Cash dividends declared on common stock         (922)
Balance, December 31, 2011 418,216,437
 $42
 $9,765
 $426
 $3,047
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


148


FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
  As of December 31,
(In millions) 2011 2010 2009
CASH FLOWS FROM OPERATING ACTIVITIES:      
Net income $869
 $718
 $856
Adjustments to reconcile net income to net cash from operating activities-  
    
Provision for depreciation 1,121
 768
 757
Amortization of regulatory assets, net 329
 722
 1,019
Nuclear fuel and lease amortization 201
 168
 128
Deferred purchased power and other costs (278) (254) (338)
Deferred income taxes and investment tax credits, net 798
 450
 323
Impairments of long-lived assets (Note 11) 413
 388
 6
Investment impairments (Note 1) 19
 33
 62
Deferred rents and lease market valuation liability (49) (54) (52)
Stock based compensation (10) (1) 20
Pensions and OPEB mark-to-market adjustment 507
 190
 321
Accrued compensation and retirement benefits (82) (65) (124)
Gain on asset sales (545) (2) (27)
Cash collateral, net (79) (26) 30
Gain on sales of investment securities held in trusts, net (59) (55) (176)
Loss on debt redemption —
 5
 146
Interest rate swap transactions —
 129
 —
Commodity derivative transactions, net (Note 10) (27) (81) 229
Pension trust contributions (372) —
 (500)
Uncertain tax positions (12) (34) (210)
Acquisition of supply requirements —
 —
 (93)
Decrease (increase) in operating assets-      
Receivables 147
 (177) 75
Materials and supplies 14
 2
 (11)
Prepayments and other current assets 101
 100
 (19)
Increase (decrease) in operating liabilities-      
Accounts payable 35
 43
 50
Accrued taxes 91
 57
 (103)
Accrued interest (12) 7
 67
Other (57) 45
 29
Net cash provided from operating activities 3,063
 3,076
 2,465
       
CASH FLOWS FROM FINANCING ACTIVITIES:      
New financing-      
Long-term debt 604
 1,099
 4,632
Redemptions and repayments-      
Long-term debt (1,909) (1,015) (2,610)
Short-term borrowings, net (700) (378) (1,246)
Common stock dividend payments (881) (670) (670)
Other (38) (19) (57)
Net cash provided from (used for) financing activities (2,924) (983) 49
       
CASH FLOWS FROM INVESTING ACTIVITIES:      
Property additions (2,278) (1,963) (2,203)
Proceeds from asset sales 840
 117
 21
Sales of investment securities held in trusts 4,207
 3,172
 2,229
Purchases of investment securities held in trusts (4,309) (3,219) (2,306)
Customer acquisition costs (3) (113) —
Cash investments (Note 9) 60
 66
 60
Cash received in Allegheny merger 590
 —
 —
Cost of removal (114) (35) (41)
Other 51
 27
 55
Net cash used for investing activities (956) (1,948) (2,185)
       
Net change in cash and cash equivalents (817) 145
 329
Cash and cash equivalents at beginning of year 1,019
 874
 545
Cash and cash equivalents at end of year $202
 $1,019
 $874
       
SUPPLEMENTAL CASH FLOW INFORMATION:      
Non-cash transaction: merger with Allegheny, common stock issued $4,354
 $—
 $—
Cash paid (received) during the year-      
Interest (net of amounts capitalized) $935
 $662
 $718
Income taxes $(358) $(42) $173
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


149


FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
  For the Years Ended December 31,
(In millions) 2011 2010 2009
STATEMENTS OF INCOME      
REVENUES:      
Electric sales to affiliates (Note 17) $752
 $2,227
 $2,826
Electric sales to non-affiliates 4,502
 3,252
 1,447
Other 223
 349
 455
Total revenues 5,477
 5,828
 4,728
       
OPERATING EXPENSES:      
Fuel 1,344
 1,403
 1,129
Purchased power from affiliates (Note 17) 242
 371
 222
Purchased power from non-affiliates 1,378
 1,585
 996
Other operating expenses 1,630
 1,230
 1,143
Pensions and OPEB mark-to-market adjustment 171
 107
 150
Provision for depreciation 275
 246
 262
General taxes 124
 94
 87
Impairment of long-lived assets 294
 388
 6
Total operating expenses 5,458
 5,424
 3,995
       
OPERATING INCOME 19
 404
 733
       
OTHER INCOME (EXPENSE) (Note 17):      
Investment income 57
 59
 125
Miscellaneous income 30
 17
 13
Interest expense (211) (216) (152)
Capitalized interest 35
 92
 60
Total other income (expense) (89) (48) 46
       
INCOME (LOSS) BEFORE INCOME TAXES (70) 356
 779
       
INCOME TAXES (BENEFITS) (11) 125
 281
       
NET INCOME (LOSS) $(59) $231
 $498
       
STATEMENTS OF COMPREHENSIVE INCOME      
       
NET INCOME (LOSS) $(59) $231
 $498
       
OTHER COMPREHENSIVE INCOME      
Pensions and OPEB prior service costs (12) (30) 68
Unrealized gain (loss) on derivative hedges 13
 8
 (49)
Change in unrealized gain on available for sale securities 15
 23
 18
Other comprehensive income 16
 1
 37
Income taxes on other comprehensive income 2
 4
 14
Other comprehensive income (loss), net of tax 14
 (3) 23
COMPREHENSIVE INCOME (LOSS) $(45) $228
 $521
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


150


FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED BALANCE SHEETS
  As of December 31,
(In millions, except share amounts) 2011 2010
ASSETS    
CURRENT ASSETS:    
Cash and cash equivalents $7
 $9
Receivables-    
Customers, net of allowance for uncollectible accounts of $16 in 2011 and $17 in 2010 424
 366
Affiliated companies 600
 478
Other, net of allowance for uncollectible accounts of $3 in 2011 and $7 in 2010 61
 90
Notes receivable from affiliated companies 383
 397
Materials and supplies, at average cost 492
 545
Derivatives 219
 181
Prepayments and other 38
 60
  2,224
 2,126
PROPERTY, PLANT AND EQUIPMENT:    
In service 10,983
 11,427
Less — Accumulated provision for depreciation 4,110
 4,038
  6,873
 7,389
Construction work in progress 1,014
 1,063
  7,887
 8,452
INVESTMENTS:    
Nuclear plant decommissioning trusts 1,223
 1,146
Other 7
 12
  1,230
 1,158
DEFERRED CHARGES AND OTHER ASSETS:    
Customer intangibles 123
 134
Goodwill 24
 24
Property taxes 43
 41
Unamortized sale and leaseback costs 80
 73
Derivatives 118
 98
Other 90
 49
  478
 419
  $11,819
 $12,155
LIABILITIES AND CAPITALIZATION    
CURRENT LIABILITIES:    
Currently payable long-term debt $905
 $1,132
Short-term borrowings - affiliated companies —
 12
Accounts payable-    
Affiliated companies 436
 466
Other 220
 241
Accrued taxes 227
 70
Derivatives 189
 266
Other 261
 252
  2,238
 2,439
CAPITALIZATION:    
Common stockholder’s equity -    
Common stock, without par value, authorized 750 shares - 7 shares outstanding 1,570
 1,567
Accumulated other comprehensive income 76
 62
Retained earnings 1,931
 1,990
Total equity 3,577
 3,619
Long-term debt and other long-term obligations 2,799
 3,181
  6,376
 6,800
NONCURRENT LIABILITIES:    
Deferred gain on sale and leaseback transaction 925
 959
Accumulated deferred income taxes 286
 67
Asset retirement obligations 904
 892
Retirement benefits 356
 285
Lease market valuation liability 171
 217
Other 563
 496
  3,205
 2,916
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Notes 6 & 16) 
 
  $11,819
 $12,155
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


151


FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
  Common Stock Accumulated Other Comprehensive Income Retained Earnings
(In millions, except share amounts) Number of Shares Carrying Value  
Balance, January 1, 2009 7
 $1,541
 $42
 $1,261
Net income       498
Change in unrealized loss on derivative instruments, net of $7 of income taxes     11
  
Change in unrealized gain on investments, net of $21 of income tax benefits     (28)  
Pensions and OPEB, net of $28 of income taxes (Note 3)     40
  
Stock options exercised, restricted stock units and other adjustments   1
    
Consolidated tax benefit allocation   3
    
Balance, December 31, 2009 7
 1,545

65

1,759
Net income       231
Change in unrealized gain on derivative instruments, net of $9 of income taxes     14
  
Change in unrealized gain on investments, net of $3 of income taxes     5
  
Pensions and OPEB, net of $8 of income tax benefits (Note 3)     (22)  
Consolidated tax benefit allocation   22
    
Balance, December 31, 2010 7
 1,567
 62
 1,990
Net loss       (59)
Change in unrealized gain on derivative instruments, net of $5 of income taxes     7
  
Change in unrealized gain on investments, net of $6 of income taxes     10
  
Pensions and OPEB, net of $9 of income tax benefits (Note 3)     (3)  
Consolidated tax benefit allocation   3
    
Balance, December 31, 2011 7
 $1,570
 $76
 $1,931
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


152


FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
  For the Years Ended December 31,
(In millions) 2011 2010 2009
CASH FLOWS FROM OPERATING ACTIVITIES:      
Net Income (loss) $(59) $231
 $498
Adjustments to reconcile net income to net cash from operating activities-      
Provision for depreciation 275
 246
 262
Nuclear fuel and lease amortization 200
 172
 130
Deferred rents and lease market valuation liability (42) (47) (46)
Deferred income taxes and investment tax credits, net 199
 150
 186
Impairments of long-lived assets (Note 11) 294
 388
 6
Investment impairments (Note 1) 17
 32
 57
Pensions and OPEB mark-to-market adjustment 171
 107
 150
Accrued compensation and retirement benefits (41) (25) (34)
Commodity derivative transactions, net (Note 10) (68) (81) 229
Gain on investment securities held in trusts, net (50) (51) (158)
Acquisition of supply requirements —
 —
 (93)
Cash collateral, net (88) (7) 20
Affiliated company lease assignment —
 —
 71
Decrease (increase) in operating assets-      
Receivables (126) (362) (34)
Materials and supplies 16
 (11) 13
Prepayments and other current assets 22
 42
 (26)
Increase (decrease) in operating liabilities-      
Accounts payable (54) (27) 68
Accrued taxes 159
 2
 6
Accrued interest —
 (2) 46
Other (6) 29
 23
Net cash provided from operating activities 819
 786
 1,374
       
CASH FLOWS FROM FINANCING ACTIVITIES:      
New financing-      
Long-term debt 247
 715
 2,438
Short-term borrowings, net (11) 2
 —
Redemptions and repayments-      
Long-term debt (856) (772) (709)
Short-term borrowings, net —
 —
 (1,156)
Other (11) (2) (21)
Net cash provided from (used for) financing activities (631) (57) 552
       
CASH FLOWS FROM INVESTING ACTIVITIES:      
Property additions (749) (1,035) (1,223)
Proceeds from asset sales 599
 117
 18
Sales of investment securities held in trusts 1,843
 1,927
 1,379
Purchases of investment securities held in trusts (1,890) (1,974) (1,406)
Loans to affiliated companies, net 14
 408
 (676)
Customer acquisition costs (3) (113) —
Leasehold improvement payments to affiliated companies —
 (51) —
Other (4) 1
 (18)
Net cash used for investing activities (190) (720) (1,926)
       
Net change in cash and cash equivalents (2) 9
 —
Cash and cash equivalents at beginning of period 9
 —
 —
Cash and cash equivalents at end of period $7
 $9
 $—
       
SUPPLEMENTAL CASH FLOW INFORMATION:      
Cash paid (received) during the year-      
Interest (net of amounts capitalized) $167
 $117
 $38
Income taxes $(387) $140
 $96
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


153


OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
  For the Years Ended December 31,
(In millions) 2011 2010 2009
STATEMENTS OF INCOME      
REVENUES (Note 17):      
Electric sales $1,526
 $1,729
 $2,418
Excise and gross receipts tax collections 107
 107
 99
Total revenues 1,633
 1,836
 2,517
       
OPERATING EXPENSES (Note 17):      
Purchased power from affiliates 287
 522
 993
Purchased power from non-affiliates 272
 316
 481
Other operating expenses 451
 342
 439
Pensions and OPEB mark-to-market adjustment 43
 24
 26
Provision for depreciation 93
 91
 92
Amortization of regulatory assets, net 30
 63
 94
General taxes 190
 183
 171
Total operating expenses 1,366
 1,541
 2,296
       
OPERATING INCOME 267
 295
 221
       
OTHER INCOME (EXPENSE) (Note 17):      
Investment income 23
 22
 47
Miscellaneous income 2
 4
 3
Interest expense (88) (89) (91)
Capitalized interest 2
 1
 1
Total other expense (61) (62) (40)
       
INCOME BEFORE INCOME TAXES 206
 233
 181
       
INCOME TAXES 78
 78
 62
       
NET INCOME $128
 $155
 $119
       
STATEMENTS OF COMPREHENSIVE INCOME      
       
NET INCOME $128
 $155
 $119
       
OTHER COMPREHENSIVE INCOME (LOSS):      
Pensions and OPEB prior service costs (43) (31) 53
Change in unrealized gain on available-for-sale securities —
 —
 (9)
Other comprehensive income (loss) (43) (31) 44
Income tax benefits on other comprehensive income (15) (9) 19
Other comprehensive income (loss), net of tax (28) (22) 25
       
COMPREHENSIVE INCOME $100
 $133
 $144
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


154


OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
  As of December 31,
(In millions, except share amounts) 2011 2010
ASSETS    
CURRENT ASSETS:    
Cash and cash equivalents $26
 $420
Receivables-    
Customers, net of allowance for uncollectible accounts of $4 in 2011 and 2010 163
 177
Affiliated companies 86
 118
Other 41
 12
Notes receivable from affiliated companies 181
 17
Prepayments and other 17
 7
  514
 751
UTILITY PLANT:    
In service 3,358
 3,222
Less — Accumulated provision for depreciation 1,267
 1,218
  2,091
 2,004
Construction work in progress 91
 45
  2,182
 2,049
OTHER PROPERTY AND INVESTMENTS:    
Investment in lease obligation bonds (Note 6) 163
 190
Nuclear plant decommissioning trusts 137
 127
Other 90
 96
  390
 413
DEFERRED CHARGES AND OTHER ASSETS:    
Regulatory assets 363
 403
Pension assets (Note 3) 5
 29
Property taxes 81
 71
Unamortized sale and leaseback costs 25
 30
Other 14
 18
  488
 551
  $3,574
 $3,764
LIABILITIES AND CAPITALIZATION    
CURRENT LIABILITIES:    
Currently payable long-term debt $2
 $1
Short-term borrowings - affiliated companies —
 142
Accounts payable-    
Affiliated companies 119
 99
Other 35
 30
Accrued taxes 88
 80
Accrued interest 25
 25
Other 79
 76
  348
 453
CAPITALIZATION:    
Common stockholder’s equity -    
Common stock, without par value, authorized 175,000,000 shares - 60 shares outstanding 747
 913
Accumulated other comprehensive income 54
 82
Accumulated deficit (84) (112)
Total common stockholder’s equity 717
 883
Noncontrolling interest 5
 6
Total equity 722
 889
Long-term debt and other long-term obligations 1,155
 1,152
  1,877
 2,041
NONCURRENT LIABILITIES:    
Accumulated deferred income taxes 787
 737
Accumulated deferred investment tax credits 9
 10
Retirement benefits 213
 184
Asset retirement obligations 71
 74
Other 269
 265
  1,349
 1,270
COMMITMENTS AND CONTINGENCIES (Notes 6 and 16) 
 
  $3,574
 $3,764
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


155


OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
  Common Stock Accumulated Other Comprehensive Income Retained Earnings (Accumulated Deficit)
(In millions, except share amounts) Number of Shares Carrying Value  
Balance, January 1, 2009 60
 $1,185
 $79
 $5
Net income       119
Change in unrealized gain on investments, net of $4 of income tax benefits     (5)  
Pensions and OPEB, net of $23 of income taxes (Note 3)     30
  
Stock-based compensation   5
    
Cash dividends declared on common stock       (346)
Cash dividend as return of capital   (74)    
Balance, December 31, 2009 60
 1,116
 104
 (222)
Net income       155
Pensions and OPEB, net of $9 of income taxes (Note 3)     (22)  
Consolidated tax benefit allocation   2
    
Cash dividends declared on common stock       (45)
Cash dividends as return of capital   (205)    
Balance, December 31, 2010 60
 913
 82
 (112)
Net income       128
Pensions and OPEB, net of $15 of income tax benefits (Note 3)     (28)  
Consolidated tax benefit allocation   2
    
Cash dividends declared on common stock       (100)
Cash dividends as return of capital   (168)    
Balance, December 31, 2011 60
 $747
 $54
 $(84)
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


156


OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
  For the Years Ended December 31,
(In millions) 2011 2010 2009
CASH FLOWS FROM OPERATING ACTIVITIES:      
Net income $128
 $155
 $119
Adjustments to reconcile net income to net cash from operating activities-      
Provision for depreciation 93
 91
 92
Amortization of regulatory assets, net 30
 63
 94
Amortization of lease costs (9) (9) (8)
Deferred income taxes and investment tax credits, net 77
 43
 37
Pensions and OPEB mark-to-market adjustment 43
 24
 26
Accrued compensation and retirement benefits (37) (45) (36)
Cash collateral, net (6) 2
 6
Pension trust contributions (27) —
 (103)
Asset retirement obligation settlements (2) (10) —
Decrease (increase) in operating assets-      
Receivables 43
 27
 140
Prepayments and other current assets (11) 14
 (10)
Increase (decrease) in operating liabilities-      
Accounts payable (5) (21) (15)
Accrued taxes 10
 (3) (9)
Other —
 (4) 23
Net cash provided from operating activities 327
 327
 356
       
CASH FLOWS FROM FINANCING ACTIVITIES:      
New financing-      
Long-term debt —
 —
 100
Short-term borrowings, net —
 49
 92
Redemptions and repayments-      
Long-term debt —
 (10) (102)
Short-term borrowings, net (142) —
 —
Common stock dividend payments (268) (250) (420)
Other (5) (2) (2)
Net cash used for financing activities (415) (213) (332)
       
CASH FLOWS FROM INVESTING ACTIVITIES:      
Property additions (149) (150) (153)
Leasehold improvement payments from affiliated companies —
 18
 —
Sales of investment securities held in trusts 154
 83
 131
Purchases of investment securities held in trusts (161) (89) (139)
Loans to affiliated companies, net (164) 102
 102
Collection of principal on long-term notes receivable —
 —
 196
Cash investments 27
 25
 20
Other (13) (7) (3)
Net cash provided from (used for) investing activities (306) (18) 154
       
Net change in cash and cash equivalents (394) 96
 178
Cash and cash equivalents at beginning of year 420
 324
 146
Cash and cash equivalents at end of year 26
 $420
 $324
       
SUPPLEMENTAL CASH FLOW INFORMATION:      
Cash paid (received) during the year-      
Interest (net of amounts capitalized) $82
 $83
 $87
Income taxes $(69) $76
 $21
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


157


THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
  For the Years Ended December 31,
(In thousands) 2011 2010 2009
STATEMENTS OF INCOME      
REVENUES (Note 17):      
Electric sales $808,778
 $1,152,950
 $1,609,946
Excise tax collections 68,009
 68,422
 66,192
Total revenues 876,787
 1,221,372
 1,676,138
       
OPERATING EXPENSES (Note 17):      
Purchased power from affiliates 143,030
 361,317
 734,592
Purchased power from non-affiliates 93,242
 129,054
 245,809
Other operating expenses 129,716
 115,066
 148,567
Pensions and OPEB mark-to-market adjustment 20,069
 11,945
 38,329
Provision for depreciation 76,135
 74,907
 73,883
Amortization of regulatory assets, net 52,846
 169,541
 236,380
General taxes 154,487
 143,294
 145,324
Total operating expenses 669,525
 1,005,124
 1,622,884
       
OPERATING INCOME 207,262
 216,248
 53,254
       
OTHER INCOME (EXPENSE) (Note 17):      
Investment income 23,565
 27,360
 31,194
Miscellaneous income 3,959
 2,362
 3,911
Interest expense (129,679) (133,351) (137,171)
Capitalized interest 608
 63
 261
Total other expense (101,547) (103,566) (101,805)
       
INCOME (LOSS) BEFORE INCOME TAXES 105,715
 112,682
 (48,551)
       
INCOME TAXES 33,852
 35,127
 (19,794)
       
NET INCOME (LOSS) 71,863
 77,555
 (28,757)
       
Income attributable to noncontrolling interest 1,293
 1,517
 1,714
       
EARNINGS AVAILABLE (LOSSES APPLICABLE) TO PARENT $70,570
 $76,038
 $(30,471)
       
STATEMENTS OF COMPREHENSIVE INCOME      
       
NET INCOME (LOSS) $71,863
 $77,555
 $(28,757)
       
OTHER COMPREHENSIVE INCOME (LOSS):      
Pensions and OPEB prior service costs (13,689) (40,442) 46,188
Income taxes (benefits) on other comprehensive income (6,842) (14,732) 19,297
Other comprehensive income (loss), net of tax (6,847) (25,710) 26,891
       
COMPREHENSIVE INCOME (LOSS) 65,016
 51,845
 (1,866)
       
Comprehensive income attributable to noncontrolling interest 1,293
 1,517
 1,714
       
COMPREHENSIVE INCOME AVAILABLE (LOSSES APPLICABLE) TO PARENT $63,723
 $50,328
 $(3,580)
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


158


THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
  As of December 31,
(In thousands, except share amounts) 2011 2010
ASSETS    
CURRENT ASSETS:    
Cash and cash equivalents $244
 $238
Receivables-    
Customers, net of allowance for uncollectible accounts of $2,933 in 2011 and $4,589 in 2010 91,967
 183,744
Affiliated companies 15,139
 77,047
Other 13,036
 11,544
Notes receivable from affiliated companies 123,712
 23,236
Prepayments and other 12,552
 3,656
  256,650
 299,465
UTILITY PLANT:    
In service 2,555,617
 2,460,117
Less — Accumulated provision for depreciation 974,229
 944,617
  1,581,388
 1,515,500
Construction work in progress 33,986
 38,610
  1,615,374
 1,554,110
OTHER PROPERTY AND INVESTMENTS:    
Investment in lessor notes 286,812
 340,029
Other 10,024
 10,074
  296,836
 350,103
DEFERRED CHARGES AND OTHER ASSETS:    
Goodwill 1,688,521
 1,688,521
Regulatory assets 295,284
 369,829
Other 98,928
 92,100
  2,082,733
 2,150,450
  $4,251,593
 $4,354,128
LIABILITIES AND CAPITALIZATION    
CURRENT LIABILITIES:    
Currently payable long-term debt $743
 $161
Short-term borrowings from affiliated companies 23,303
 105,996
Accounts payable-    
Affiliated companies 31,786
 32,020
Other 8,548
 14,947
Accrued taxes 86,440
 85,346
Accrued interest 18,549
 18,555
Other 34,124
 44,569
  203,493
 301,594
CAPITALIZATION:    
Common stockholder’s equity    
Common stock, without par value, authorized 105,000,000 shares -
67,930,743 shares outstanding
 865,570
 863,372
Accumulated other comprehensive income 27,264
 34,111
Retained earnings 388,246
 381,676
Common stockholder’s equity 1,281,080
 1,279,159
Noncontrolling interest 15,195
 18,017
Total equity 1,296,275
 1,297,176
Long-term debt and other long-term obligations 1,834,890
 1,852,530
  3,131,165
 3,149,706
NONCURRENT LIABILITIES:    
Accumulated deferred income taxes 662,805
 647,292
Accumulated deferred investment tax credits 10,153
 10,994
Retirement benefits 86,619
 95,654
Other 157,358
 148,888
  916,935
 902,828
COMMITMENTS AND CONTINGENCIES (Note 6 and 16) 
 
  $4,251,593
 $4,354,128
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


159


THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
  Common Stock Accumulated Other Comprehensive Income Retained Earnings
(In thousands, except share amounts) Number of Shares Carrying Value  
Balance, January 1, 2009 67,930,743
 $855,070
 $32,930
 $686,109
Losses applicable to parent       (30,471)
Pensions and OPEB, net of $19,297 of income taxes (Note 3)   
 26,891
  
Restricted stock units   74
    
Consolidated tax benefit allocation   6,038
    
Cash dividends declared on common stock       (250,000)
Balance, December 31, 2009 67,930,743
 861,182
 59,821
 405,638
Earnings available to parent       76,038
Pensions and OPEB, net of $14,732 of income tax benefit (Note 3)   
 (25,710)  
Restricted stock units   55
    
Consolidated tax benefit allocation   2,135
    
Cash dividends declared on common stock       (100,000)
Balance, December 31, 2010 67,930,743
 863,372
 34,111
 381,676
Earnings available to parent       70,570
Pensions and OPEB, net of $6,842 of income tax benefits (Note 3)   
 (6,847)  
Restricted stock units   (30)    
Consolidated tax benefit allocation   2,228
    
Cash dividends declared on common stock       (64,000)
Balance, December 31, 2011 67,930,743
 $865,570
 $27,264
 $388,246
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


160


THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
  For the Years Ended December 31,
(In thousands) 2011 2010 2009
CASH FLOWS FROM OPERATING ACTIVITIES:      
Net income (loss) $71,863
 $77,555
 $(28,757)
Adjustments to reconcile net income (loss) to net cash from operating activities-      
Provision for depreciation 76,135
 74,907
 73,883
Amortization of regulatory assets, net 52,846
 169,541
 236,380
Deferred income taxes and investment tax credits, net 23,931
 (23,614) (61,450)
Pensions and OPEB mark-to-market adjustment 20,069
 11,945
 38,329
Accrued compensation and retirement benefits (11,951) (2,228) (4,326)
Electric service prepayment programs —
 —
 (3,510)
Cash collateral, net (5,016) 889
 5,440
Lease assignment payments to affiliated company —
 —
 (40,827)
Pension trust contributions (35,000) —
 (89,789)
Uncertain tax positions 46
 (2,872) 10,766
Decrease (increase) in operating assets-      
Receivables 164,848
 60,762
 65,603
Prepayments and other current assets (8,896) 6,075
 (7,186)
Increase (decrease) in operating liabilities-      
Accounts payable (19,277) (38,833) (3,479)
Accrued taxes 1,094
 (3,700) 2,533
Accrued interest (7) 89
 4,534
Other (1,796) 2,109
 8,732
Net cash provided from operating activities 328,889
 332,625
 206,876
       
CASH FLOWS FROM FINANCING ACTIVITIES:      
New financing-      
Long-term debt —
 —
 298,398
Short-term borrowings, net —
 —
 93,577
Redemptions and repayments-      
Long-term debt (177) (117) (151,273)
Short-term borrowings, net (104,228) (254,048) —
Common stock dividend payments (64,000) (100,000) (275,000)
Other (5,879) (4,100) (6,427)
Net cash used for financing activities (174,284) (358,265) (40,725)
       
CASH FLOWS FROM INVESTING ACTIVITIES:      
Property additions (96,504) (105,660) (103,243)
Loans to affiliated companies, net (100,476) 3,566
 (7,741)
Investment in lessor notes 53,217
 48,612
 37,074
Other (10,836) (6,870) (6,237)
Net cash used for investing activities (154,599) (60,352) (80,147)
       
Net change in cash and cash equivalents 6
 (85,992) 86,004
Cash and cash equivalents at beginning of year 238
 86,230
 226
Cash and cash equivalents at end of year $244
 $238
 $86,230
       
SUPPLEMENTAL CASH FLOW INFORMATION:      
Cash paid (received) during the year-      
Interest (net of amounts capitalized) $127,268
 $131,546
 $130,689
Income taxes $(40,551) $67,651
 $29,358
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


161


THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
  For the Years Ended December 31,
(In thousands) 2011 2010 2009
STATEMENTS OF INCOME      
REVENUES (Note 17):      
Electric sales $448,988
 $489,310
 $810,069
Excise tax collections 27,983
 27,387
 23,839
Total revenues 476,971
 516,697
 833,908
       
OPERATING EXPENSES (Note 17):      
Purchased power from affiliates 94,351
 180,523
 392,825
Purchased power from non-affiliates 74,022
 64,174
 136,210
Other operating expenses 133,366
 101,895
 135,938
Pensions and OPEB mark-to-market adjustment 10,560
 4,183
 14,360
Provision for depreciation 32,467
 32,161
 31,181
Amortization (deferral) of regulatory assets, net (1,679) (1,427) 37,820
General taxes 53,911
 52,045
 47,815
Total operating expenses 396,998
 433,554
 796,149
       
OPERATING INCOME 79,973
 83,143
 37,759
       
OTHER INCOME (EXPENSE) (Note 17):      
Investment income 11,054
 14,727
 24,388
Miscellaneous expense (366) (4,287) (2,169)
Interest expense (41,876) (41,883) (36,512)
Capitalized interest 547
 304
 283
Total other expense (30,641) (31,139) (14,010)
       
INCOME BEFORE INCOME TAXES 49,332
 52,004
 23,749
       
INCOME TAXES 14,605
 15,756
 5,347
       
NET INCOME 34,727
 36,248
 18,402
       
Income attributable to noncontrolling interest 7
 4
 21
       
EARNINGS AVAILABLE TO PARENT $34,720
 $36,244
 $18,381
       
STATEMENTS OF COMPREHENSIVE INCOME      
       
NET INCOME $34,727
 $36,248
 $18,402
       
OTHER COMPREHENSIVE LOSS:      
Pensions and OPEB prior service costs (5,810) (6,950) 9,078
Change in unrealized gain on available-for-sale securities 4,506
 131
 (15,181)
Other comprehensive loss (1,304) (6,819) (6,103)
Income tax benefits on other comprehensive loss (1,296) (1,421) (533)
Other comprehensive loss, net of tax (8) (5,398) (5,570)
       
COMPREHENSIVE INCOME 34,719
 30,850
 12,832
       
Comprehensive income attributable to noncontrolling interest 7
 4
 21
       
COMPREHENSIVE INCOME AVAILABLE TO PARENT $34,712
 $30,846
 $12,811
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


162


THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
  As of December 31,
(In thousands, except share amounts) 2011 2010
ASSETS    
CURRENT ASSETS:    
Cash and cash equivalents $12
 $149,262
Receivables-    
Customers, net of allowance for uncollectible accounts of $1,467 in 2011 and $1 in 2010 49,014
 29
Affiliated companies 30,925
 31,777
Other, net of allowance for uncollectible accounts of $264 in 2011 and $330 in 2010 2,670
 18,464
Notes receivable from affiliated companies 187,086
 96,765
Prepayments and other 7,925
 2,306
  277,632
 298,603
UTILITY PLANT:    
In service 999,146
 962,428
Less — Accumulated provision for depreciation 464,204
 450,531
  534,942
 511,897
Construction work in progress 11,513
 12,604
  546,455
 524,501
OTHER PROPERTY AND INVESTMENTS:    
Investment in lessor notes (Note 6) 82,153
 103,872
Nuclear plant decommissioning trusts 83,125
 75,558
Other 1,442
 1,492
  166,720
 180,922
DEFERRED CHARGES AND OTHER ASSETS:    
Goodwill 500,576
 500,576
Regulatory assets 70,235
 72,588
Other 60,895
 48,740
  631,706
 621,904
  $1,622,513
 $1,625,930
LIABILITIES AND CAPITALIZATION    
CURRENT LIABILITIES:    
Currently payable long-term debt $193
 $199
Accounts payable-    
Affiliated companies 22,424
 17,168
Other 8,847
 7,351
Accrued taxes 34,850
 24,623
Lease market valuation liability 36,900
 36,900
Other 30,753
 29,075
  133,967
 115,316
CAPITALIZATION:    
Common stockholder’s equity -    
Common stock, without par value, authorized 60,000,000 shares - 29,402,054 shares outstanding 147,010
 147,010
Other paid-in capital 163,013
 163,021
Accumulated other comprehensive income 15,078
 15,086
Retained earnings 43,220
 42,500
Total common stockholder’s equity 368,321
 367,617
Noncontrolling interest 2,596
 2,589
Total equity 370,917
 370,206
Long-term debt and other long-term obligations 598,869
 600,493
  969,786
 970,699
NONCURRENT LIABILITIES:    
Accumulated deferred income taxes 170,385
 140,715
Accumulated deferred investment tax credits 5,499
 5,930
Retirement benefits 50,537
 71,486
Asset retirement obligations 30,745
 28,762
Lease market valuation liability (Note 6) 162,400
 199,300
Other 99,194
 93,722
  518,760
 539,915
COMMITMENTS AND CONTINGENCIES (Notes 6 and 16) 
 
  $1,622,513
 $1,625,930
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


163


THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
  Common Stock Other Paid-In Capital Accumulated Other Comprehensive Income Retained Earnings
(In thousands, except share amounts) Number of Shares Par Value   
Balance, January 1, 2009 29,402,054
 $147,010
 $160,718
 $26,054
 $117,875
Earnings available to parent         18,381
Change in unrealized gain on investments, net of $5,756 of income taxes       (9,425)  
Pensions and OPEB, net of $5,223 of income tax benefits (Note 3)       3,855
  
Restricted stock units     71
    
Consolidated tax benefit allocation     2,231
    
Balance, December 31, 2009 29,402,054
 147,010
 163,020
 20,484
 136,256
Earnings available to parent         36,244
Change in unrealized gain on investments, net of $46 of income tax benefits       85
  
Pensions and OPEB, net of $1,467 of income tax benefits (Note 3)       (5,483)  
Restricted stock units     1
    
Cash dividends declared on common stock     

   (130,000)
Balance, December 31, 2010 29,402,054
 147,010
 163,021
 15,086
 42,500
Earnings available to parent         34,720
Change in unrealized gain on investments, net of $1,610 of income taxes       2,896
  
Pensions and OPEB, net of $2,906 of income tax benefits (Note 3)       (2,904)  
Restricted stock units     (8)    
Cash dividends declared on common stock         (34,000)
Balance, December 31, 2010 29,402,054
 $147,010
 $163,013
 $15,078
 $43,220
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


164


THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
  For the Years Ended December 31,
(In thousands) 2011 2010 2009
CASH FLOWS FROM OPERATING ACTIVITIES:      
Net income $34,727
 $36,248
 $18,402
Adjustments to reconcile net income to net cash from operating activities-      
Provision for depreciation 32,467
 32,161
 31,181
Amortization (deferral) of regulatory assets, net (1,679) (1,427) 37,820
Deferred rents and lease market valuation liability (37,839) (37,839) (37,839)
Deferred income taxes and investment tax credits, net 35,739
 26,152
 (589)
Pensions and OPEB mark-to-market adjustment 10,560
 4,183
 14,360
Accrued compensation and retirement benefits (4,640) (660) (2,776)
Electric service prepayment programs —
 —
 (1,458)
Pension trust contributions (45,000) —
 (21,590)
Cash collateral, net (2,583) 1,548
 2,794
Lease assignment payment to affiliated company —
 —
 (30,529)
Gain on sales of investment securities held in trusts (2,337) (2,348) (7,130)
Uncertain tax positions 10
 (1,831) 3,038
Decrease (increase) in operating assets-      
Receivables (31,322) 82,369
 (18,872)
Prepayments and other current assets (5,807) 6,464
 (5,898)
Increase (decrease) in operating liabilities-      
Accounts payable 264
 (60,183) 35,192
Accrued taxes 10,228
 (1,333) (1,932)
Other 6,451
 (7,554) 6,754
Net cash provided from operating activities (761) 75,950
 20,928
       
CASH FLOWS FROM FINANCING ACTIVITIES:      
New financing-      
Long-term debt —
 —
 297,422
Short-term borrowings, net —
 —
 114,733
Redemptions and repayments-      
Long-term debt (139) (222) (347)
Short-term borrowings, net —
 (225,975) —
Common stock dividend payments (34,000) (130,000) (25,000)
Other (1,762) (112) (351)
Net cash provided from (used for) financing activities (35,901) (356,309) 386,457
       
CASH FLOWS FROM INVESTING ACTIVITIES:      
Property additions (37,324) (42,097) (47,028)
Leasehold improvement payments from associated companies —
 32,829
 —
Loans to affiliated companies, net (90,322) (11,664) 63,711
Redemption of lessor notes (Note 6) 21,719
 20,485
 18,330
Sales of investment securities held in trusts 120,460
 125,557
 168,580
Purchases of investment securities held in trusts (123,052) (127,323) (170,996)
Other (4,069) (4,878) (3,284)
Net cash provided from (used for) investing activities (112,588) (7,091) 29,313
       
Net change in cash and cash equivalents (149,250) (287,450) 436,698
Cash and cash equivalents at beginning of year 149,262
 436,712
 14
Cash and cash equivalents at end of year $12
 $149,262
 $436,712
       
SUPPLEMENTAL CASH FLOW INFORMATION:      
Cash paid (received) during the year-      
Interest (net of amounts capitalized) $40,780
 $41,162
 $32,353
Income taxes $(32,884) $(13,456) $1,350
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financialstatements.


165


JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
  For the Years Ended December 31,
(In millions) 2011 2010 2009
STATEMENTS OF INCOME      
REVENUES:      
Electric sales $2,445
 $2,976
 $2,944
Excise tax collections 50
 51
 49
Total revenues 2,495
 3,027
 2,993
       
OPERATING EXPENSES (Note 17):      
Purchased power 1,382
 1,736
 1,783
Other operating expenses 371
 323
 284
Pensions and OPEB mark-to-market adjustment 60
 26
 37
Provision for depreciation 135
 113
 108
Amortization of regulatory assets, net 108
 321
 344
General taxes 67
 65
 63
Total operating expenses 2,123
 2,584
 2,619
       
OPERATING INCOME 372
 443
 374
       
OTHER INCOME (EXPENSE) (Note 17):      
Miscellaneous income 11
 6
 5
Interest expense (124) (120) (117)
Capitalized interest 2
 1
 1
Total other expense (111) (113) (111)
       
INCOME BEFORE INCOME TAXES 261
 330
 263
       
INCOME TAXES 117
 147
 105
       
NET INCOME $144
 $183
 $158
       
STATEMENTS OF COMPREHENSIVE INCOME      
       
NET INCOME $144
 $183
 $158
       
OTHER COMPREHENSIVE LOSS:      
Pensions and OPEB prior service costs (27) (17) (18)
Other comprehensive loss (27) (17) (18)
Income tax benefits on other comprehensive loss (15) (10) (4)
Other comprehensive loss, net of tax (12) (7) (14)
       
COMPREHENSIVE INCOME $132
 $176
 $144
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


166


JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED BALANCE SHEETS
  As of December 31,
(In millions, except share amounts) 2011 2010
ASSETS    
CURRENT ASSETS:    
Receivables-    
Customers, net of allowance for uncollectible accounts of $4 in 2011 and 2010 $235
 $323
Affiliated companies —
 54
Other 17
 26
Notes receivable — affiliated companies —
 177
Prepaid taxes 33
 11
Other 19
 13
  304
 604
UTILITY PLANT:    
In service 4,872
 4,783
Less — Accumulated provision for depreciation 1,743
 1,682
  3,129
 3,101
Construction work in progress 227
 63
  3,356
 3,164
OTHER PROPERTY AND INVESTMENTS:    
Nuclear fuel disposal trust 219
 208
Nuclear plant decommissioning trusts 193
 182
Other 2
 2
  414
 392
DEFERRED CHARGES AND OTHER ASSETS:    
Goodwill 1,811
 1,811
Regulatory assets 408
 514
Other 32
 28
  2,251
 2,353
  $6,325
 $6,513
LIABILITIES AND CAPITALIZATION    
CURRENT LIABILITIES:    
Currently payable long-term debt $34
 $32
Short-term borrowings-    
Affiliated companies 259
 —
Accounts payable-    
Affiliated companies 19
 29
Other 101
 158
Accrued compensation and benefits 41
 35
Customer deposits 24
 23
Accrued interest 18
 18
Other 36
 28
  532
 323
CAPITALIZATION:    
Common stockholder’s equity -    
Common stock, $10 par value, authorized 16,000,000 shares - 13,628,447 shares outstanding 136
 136
Other paid-in capital 2,011
 2,509
Accumulated other comprehensive income 39
 51
Retained earnings (accumulated deficit) 121
 (23)
Total common stockholder’s equity 2,307
 2,673
Long-term debt and other long-term obligations 1,736
 1,770
  4,043
 4,443
NONCURRENT LIABILITIES:    
Accumulated deferred income taxes 859
 793
Power purchase contract liability 147
 233
Nuclear fuel disposal costs 197
 197
Retirement benefits 170
 182
Asset retirement obligations 115
 108
Other 262
 234
  1,750
 1,747
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Notes 6 and 16) 
 
  $6,325
 $6,513
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


As of December 31, 2009  2008 
  (In thousands) 
ASSETS      
CURRENT ASSETS:      
Cash and cash equivalents $27  $66 
Receivables-        
Customers (less accumulated provisions of $3,506,000 and $3,230,000,        
respectively, for uncollectible accounts)  300,991   340,485 
Associated companies  12,884   265 
Other  21,877   37,534 
Notes receivable - associated companies  102,932   16,254 
Prepaid taxes  34,930   10,492 
Other  12,945   18,066 
   486,586   423,162 
UTILITY PLANT:        
In service  4,463,490   4,307,556 
Less - Accumulated provision for depreciation  1,617,639   1,551,290 
   2,845,851   2,756,266 
Construction work in progress  54,251   77,317 
   2,900,102   2,833,583 
OTHER PROPERTY AND INVESTMENTS:        
Nuclear fuel disposal trust  199,677   181,468 
Nuclear plant decommissioning trusts  166,768   143,027 
Other  2,149   2,145 
   368,594   326,640 
DEFERRED CHARGES AND OTHER ASSETS:        
Regulatory assets  888,143   1,228,061 
Goodwill  1,810,936   1,810,936 
Other  27,096   29,946 
   2,726,175   3,068,943 
  $6,481,457  $6,652,328 
LIABILITIES AND CAPITALIZATION        
CURRENT LIABILITIES:        
Currently payable long-term debt $30,639  $29,094 
Short-term borrowings-        
Associated companies  -   121,380 
Accounts payable-        
Associated companies  26,882   12,821 
Other  168,093   198,742 
Accrued taxes  12,594   20,561 
Accrued interest  18,256   9,197 
Other  111,156   133,091 
   367,620   524,886 
CAPITALIZATION (See Consolidated Statements of Capitalization):
        
Common stockholder's equity  2,600,396   2,729,010 
Long-term debt and other long-term obligations  1,801,589   1,531,840 
   4,401,985   4,260,850 
NONCURRENT LIABILITIES:        
Power purchase contract liability  399,105   531,686 
Accumulated deferred income taxes  687,545   689,065 
Nuclear fuel disposal costs  196,511   196,235 
Asset retirement obligations  101,568   95,216 
Retirement benefits  150,603   190,182 
Other  176,520   164,208 
   1,711,852   1,866,592 
COMMITMENTS AND CONTINGENCIES (Notes 7 and 15)        
  $6,481,457  $6,652,328 
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

167
173


JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATIONCOMMON STOCKHOLDER’S EQUITY
  Common Stock Other Paid-In Capital Accumulated Other Comprehensive Income Retained Earnings (Accumulated Deficit)
(In millions, except share amounts) Number of Shares Par Value   
Balance, January 1, 2009 14,421,637
 $144
 $2,645
 $72
 $(72)
Net income         158
Pensions and OPEB, net of $4 of income tax benefits (Note 3)       (14)  
Cash dividends declared on common stock         (127)
Repurchase of common stock (793,190) (8) (142)    
Consolidated tax benefit allocation     4
    
Balance, December 31, 2009 13,628,447
 136
 2,507
 58
 (41)
Net income         183
Pensions and OPEB, net of $10 of income tax benefits (Note 3)       (7)  
Cash dividends declared on common stock         (165)
Consolidated tax benefit allocation     2
    
Balance, December 31, 2010 13,628,447
 136
 2,509
 51
 (23)
Net income         144
Pensions and OPEB, net of $15 of income tax benefits (Note 3)       (12)  
Cash dividends as return of capital     (500)    
Consolidated tax benefit allocation     2
    
Balance, December 31, 2011 13,628,447
 $136
 $2,011
 $39
 $121
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


As of December 31, 2009  2008 
  (In thousands) 
COMMON STOCKHOLDER'S EQUITY:      
Common stock, $10 par value, 16,000,000 shares authorized,      
13,628,447 and 14,421,637 shares outstanding, respectively $136,284  $144,216 
Other paid-in capital  2,507,049   2,644,756 
Accumulated other comprehensive loss (Note 2(F))  (243,012)  (216,538)
Retained earnings (Note 12(A))  200,075   156,576 
Total  2,600,396   2,729,010 
         
         
LONG-TERM DEBT (Note 12(C)):        
Secured notes-        
5.390% due 2008-2010  13,629   33,469 
5.250% due 2008-2012  23,974   33,229 
5.810% due 2010-2013  77,075   77,075 
5.410% due 2012-2014  25,693   25,693 
6.160% due 2013-2017  99,517   99,517 
5.520% due 2014-2018  49,220   49,220 
5.610% due 2018-2021  51,139   51,139 
Total  340,247   369,342 
         
Unsecured notes-        
5.625% due 2016  300,000   300,000 
5.650% due 2017  250,000   250,000 
4.800% due 2018  150,000   150,000 
7.350% due 2019  300,000   - 
6.400% due 2036  200,000   200,000 
6.150% due 2037  300,000   300,000 
Total  1,500,000   1,200,000 
         
         
Capital lease obligations (Note 7)  108   - 
Unamortized discount on debt  (8,127)  (8,408)
Long-term debt due within one year  (30,639)  (29,094)
Total long-term debt  1,801,589   1,531,840 
TOTAL CAPITALIZATION $4,401,985  $4,260,850 
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

168
174


JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
  For the Years Ended December 31,
(In millions) 2011 2010 2009
CASH FLOWS FROM OPERATING ACTIVITIES:      
Net income $144
 $183
 $158
Adjustments to reconcile net income to net cash from operating activities-      
Provision for depreciation 135
 113
 108
Amortization of regulatory assets, net 108
 321
 344
Deferred purchased power and other costs (93) (105) (148)
Deferred income taxes and investment tax credits, net 91
 31
 39
Pensions and OPEB mark-to-market adjustment 60
 26
 37
Accrued compensation and retirement benefits (32) (7) (13)
Cash collateral, net —
 (23) —
Pension trust contributions (105) —
 (100)
Decrease (increase) in operating assets-      
Receivables 160
 (67) 43
Prepaid taxes (22) 24
 (24)
Increase (decrease) in operating liabilities-      
Accounts payable (83) (20) (25)
Accrued taxes 11
 12
 (14)
Other 11
 (11) (3)
Net cash provided from operating activities 385
 477
 402
       
CASH FLOWS FROM FINANCING ACTIVITIES:      
New financing-      
Long-term debt —
 —
 299
Short-term borrowings, net 259
 —
 —
Redemptions and repayments-      
Long-term debt (32) (31) (29)
Short-term borrowings, net —
 —
 (121)
Common stock —
 —
 (150)
Common stock dividend payments (500) (165) (127)
Other (1) —
 (2)
Net cash used for financing activities (274) (196) (130)
       
CASH FLOWS FROM INVESTING ACTIVITIES:      
Property additions (229) (182) (166)
Loans to affiliated companies, net 177
 (74) (87)
Sales of investment securities held in trusts 779
 411
 397
Purchases of investment securities held in trusts (796) (428) (413)
Cost of removal (35) (6) (5)
Other (7) (2) 2
Net cash used for investing activities (111) (281) (272)
       
Net change in cash and cash equivalents —
 —
 —
Cash and cash equivalents at beginning of year —
 —
 —
Cash and cash equivalents at end of year $—
 $—
 $—
       
SUPPLEMENTAL CASH FLOW INFORMATION:      
Cash paid (received) during the year-      
Interest (net of amounts capitalized) $118
 $117
 $109
Income taxes $(8) $145
 $96
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


169


METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
  For the Years Ended December 31,
(In thousands) 2011 2010 2009
STATEMENTS OF INCOME      
REVENUES (Note 17):      
Electric sales $1,149,030
 $1,733,651
 $1,611,088
Gross receipts tax collections 63,511
 84,896
 77,894
Total revenues 1,212,541
 1,818,547
 1,688,982
       
OPERATING EXPENSES (Note 17):      
Purchased power from affiliates 142,858
 612,496
 365,491
Purchased power from non-affiliates 484,128
 342,988
 536,054
Other operating expenses 171,236
 401,016
 259,135
Pensions and OPEB mark-to-market adjustment 33,493
 6,993
 16,044
Provision for depreciation 60,831
 55,792
 54,652
Amortization of regulatory assets, net 92,450
 160,360
 244,709
General taxes 74,364
 87,829
 87,799
Total operating expenses 1,059,360
 1,667,474
 1,563,884
       
OPERATING INCOME 153,181
 151,073
 125,098
       
OTHER INCOME (EXPENSE) (Note 17):      
Interest income 121
 3,019
 9,709
Miscellaneous income 3,606
 5,901
 4,107
Interest expense (52,685) (52,829) (56,683)
Capitalized interest 486
 653
 181
Total other expense (48,472) (43,256) (42,686)
       
INCOME BEFORE INCOME TAXES 104,709
 107,817
 82,412
       
INCOME TAXES 36,820
 47,733
 28,875
       
NET INCOME $67,889
 $60,084
 $53,537
       
STATEMENTS OF COMPREHENSIVE INCOME      
       
NET INCOME $67,889
 $60,084
 $53,537
       
OTHER COMPREHENSIVE LOSS:      
Pensions and OPEB prior service costs (21,149) (12,968) 567
Unrealized gain on derivative hedges 335
 335
 335
Other comprehensive loss (20,814) (12,633) 902
Income taxes (benefits) on other comprehensive income (10,918) (7,552) 3,070
Other comprehensive loss, net of tax (9,896) (5,081) (2,168)
       
COMPREHENSIVE INCOME $57,993
 $55,003
 $51,369
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


170


METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
  As of December 31,
(In thousands, except share amounts) 2011 2010
ASSETS    
CURRENT ASSETS:    
Cash and cash equivalents $157
 $243,220
Receivables-    
Customers, net of allowance for uncollectible accounts of $3,015 in 2011 and $3,868 in 2010 138,587
 178,522
Affiliated companies 11,697
 24,920
Other 17,345
 13,007
Notes receivable from affiliated companies —
 11,028
Prepaid taxes 333
 343
Other 2,741
 2,289
  170,860
 473,329
UTILITY PLANT:  �� 
In service 2,475,890
 2,393,501
Less — Accumulated provision for depreciation 887,186
 862,517
  1,588,704
 1,530,984
Construction work in progress 46,868
 23,663
  1,635,572
 1,554,647
OTHER PROPERTY AND INVESTMENTS:    
Nuclear plant decommissioning trusts 309,946
 289,328
Other 865
 884
  310,811
 290,212
DEFERRED CHARGES AND OTHER ASSETS:    
Goodwill 416,499
 416,499
Regulatory assets 328,623
 295,908
Power purchase contract asset 48,868
 111,562
Other 16,304
 31,699
  810,294
 855,668
  $2,927,537
 $3,173,856
LIABILITIES AND CAPITALIZATION    
CURRENT LIABILITIES:    
Currently payable long-term debt $29,020
 $28,760
Short-term borrowings - affiliated companies 257,563
 124,079
Accounts payable-    
Associated companies 21,092
 33,942
Other 42,819
 29,862
Accrued taxes 10,056
 61,338
Accrued interest 15,996
 16,114
Other 32,015
 29,278
  408,561
 323,373
CAPITALIZATION:    
Common stockholder’s equity -    
Common stock, without par value, authorized 900,000 shares -
740,905 and 859,500 shares outstanding, respectively
 842,744
 1,197,076
Accumulated other comprehensive income 27,528
 37,424
Accumulated deficit (63,672) (106,561)
Total common stockholder’s equity 806,600
 1,127,939
Long-term debt and other long-term obligations 703,525
 718,860
  1,510,125
 1,846,799
NONCURRENT LIABILITIES:    
Accumulated deferred income taxes 539,511
 526,467
Accumulated deferred investment tax credits 6,445
 6,866
Nuclear fuel disposal costs 44,476
 44,449
Asset retirement obligations 205,891
 192,659
Retirement benefits 42,055
 29,121
Power purchase contract liability 79,188
 116,027
Other 91,285
 88,095
  1,008,851
 1,003,684
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 6 and 16) 
 
  $2,927,537
 $3,173,856
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


171


METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'SSTOCKHOLDER’S EQUITY

              Accumulated    
     Common Stock  Other  Other    
  Comprehensive  Number  Par  Paid-In  Comprehensive  Retained 
  Income  of Shares  Value  Capital  Income (Loss)  Earnings 
  (Dollars in thousands) 
                   
Balance, January 1, 2007     15,009,335   150,093   2,908,279   (44,254)  145,480 
Net income $186,108                   186,108 
Net unrealized gain on derivative instruments,                        
net of $11,000 of income taxes  293               293     
Pension and other postretirement benefits, net                        
of $23,644,000 of income taxes (Note 3)  24,080               24,080     
Comprehensive income $210,481                     
Restricted stock units              198         
Stock-based compensation              3         
Consolidated tax benefit allocation              4,637         
Repurchase of common stock      (587,698)  (5,877)  (119,123)        
Cash dividends declared on common stock                      (94,000)
Purchase accounting fair value adjustment              (138,053)        
Balance, December 31, 2007      14,421,637   144,216   2,655,941   (19,881)  237,588 
Net income $186,988                   186,988 
Net unrealized gain on derivative instruments  276               276     
Pension and other postretirement benefits, net                        
of $131,317,000 of income tax benefits (Note 3)  (196,933)              (196,933)    
Comprehensive loss $(9,669)                    
Restricted stock units              3         
Stock-based compensation              1         
Consolidated tax benefit allocation              4,065         
Cash dividends declared on common stock                      (268,000)
Purchase accounting fair value adjustment              (15,254)        
Balance, December 31, 2008      14,421,637   144,216   2,644,756   (216,538)  156,576 
Net income $170,499                   170,499 
Net unrealized gain on derivative instruments                        
net of $11,000 of income taxes  288               288     
Pension and other postretirement benefits, net                        
of $13,025,000 of income tax benefits (Note 3)  (26,762)              (26,762)    
Comprehensive income $144,025                     
Restricted stock units              99         
Cash dividends declared on common stock                      (127,000)
Repurchase of common stock      (793,190)  (7,932)  (137,806)        
Balance, December 31, 2009      13,628,447  $136,284  $2,507,049  $(243,012) $200,075 
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

175
  Common Stock Accumulated Other Comprehensive Income Accumulated Deficit
(In thousands, except share amounts) Number of Shares Carrying Value  
Balance, January 1, 2009 859,500
 $1,196,172
 $44,673
 $(190,182)
Net income       53,537
Change in unrealized loss on derivative instruments     335
  
Pensions and OPEB, net of $3,070 of income taxes (Note 3)     (2,503)  
Restricted stock units   55
    
Consolidated tax benefit allocation   843
    
Balance, December 31, 2009 859,500
 1,197,070
 42,505
 (136,645)
Net income       60,084
Change in unrealized loss on derivative instruments, net of $522 of income taxes     (187)  
Pensions and OPEB, net of $8,074 of income tax benefits (Note 3)     (4,894)  
Restricted stock units   6
    
Cash dividends declared on common stock       (30,000)
Balance, December 31, 2010 859,500
 1,197,076
 37,424
 (106,561)
Net income       67,889
Change in unrealized loss on derivative instruments, net of $139 of income taxes     196
  
Pensions and OPEB, net of $11,057 of income tax benefits (Note 3)     (10,092)  
Restricted stock units   (51)    
Consolidated tax benefit allocation   719
    
Cash dividends as return of capital   (205,000)    
Repurchase of common stock (118,595) (150,000)    
Cash dividends declared on common stock       (25,000)
Balance, December 31, 2011 740,905
 $842,744
 $27,528
 $(63,672)
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


JERSEY CENTRAL POWER & LIGHT172


METROPOLITAN EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2009  2008  2007 
  (In thousands) 
CASH FLOWS FROM OPERATING ACTIVITIES:         
Net income $170,499  $186,988  $186,108 
Adjustments to reconcile net income to net cash from operating activities-            
Provision for depreciation  102,912   96,482   85,459 
Amortization of regulatory assets  344,158   364,816   388,581 
Deferred purchased power and other costs  (148,308)  (165,071)  (203,157)
Deferred income taxes and investment tax credits, net  42,800   12,834   (30,791)
Accrued compensation and retirement benefits  12,915   (35,791)  (23,441)
Cash collateral from (returned to) suppliers  (210)  23,106   (31,938)
Pension trust contributions  (100,000)  -   (17,800)
Decrease (increase) in operating assets-            
Receivables  42,532   8,042   (73,259)
Materials and supplies  -   348   (364)
Prepayments and other current assets  (24,333)  (9,600)  14,417 
Increase (decrease) in operating liabilities-            
Accounts payable  (24,677)  10,174   (39,396)
Accrued taxes  (14,265)  2,582   11,658 
Accrued interest  9,059   (121)  (5,140)
Other  (11,246)  (13,002)  5,369 
Net cash provided from operating activities  401,836   481,787   266,306 
             
CASH FLOWS FROM FINANCING ACTIVITIES:            
New Financing-            
Long-term debt  299,619   -   543,807 
Redemptions and Repayments-            
Long-term debt  (29,094)  (27,206)  (325,337)
Short-term borrowings, net  (121,380)  (9,001)  (56,159)
Common stock  (150,000)  -   (125,000)
Dividend Payments-            
Common stock  (127,000)  (268,000)  (94,000)
Other  (2,281)  (80)  (609)
Net cash used for financing activities  (130,136)  (304,287)  (57,298)
             
CASH FLOWS FROM INVESTING ACTIVITIES:            
Property additions  (166,409)  (178,358)  (199,856)
Proceeds from asset sales  -   20,000   - 
Loan repayments from (loans to) associated companies, net  (86,678)  2,173   6,029 
Sales of investment securities held in trusts  397,333   248,185   195,973 
Purchases of investment securities held in trusts  (413,693)  (265,441)  (212,263)
Restricted funds  5,015   (689)  783 
Other  (7,307)  (3,398)  379 
Net cash used for investing activities  (271,739)  (177,528)  (208,955)
             
Net increase (decrease) in cash and cash equivalents  (39)  (28)  53 
Cash and cash equivalents at beginning of year  66   94   41 
Cash and cash equivalents at end of year $27  $66  $94 
             
SUPPLEMENTAL CASH FLOW INFORMATION:            
Cash Paid During the Year-            
Interest (net of amounts capitalized) $108,650  $99,731  $102,492 
Income taxes $95,764  $145,943  $156,073 
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

176
  For the Years Ended December 31,
(In thousands) 2011 2010 2009
CASH FLOWS FROM OPERATING ACTIVITIES:      
Net income $67,889
 $60,084
 $53,537
Adjustments to reconcile net income to net cash from operating activities-      
Provision for depreciation 60,831
 55,792
 54,652
Amortization of regulatory assets, net 92,450
 160,360
 244,709
Deferred costs recoverable as regulatory assets (88,041) (62,462) (96,304)
Deferred income taxes and investment tax credits, net 4,332
 34,395
 67,246
Pensions and OPEB mark-to-market adjustment 33,493
 6,993
 16,044
Accrued compensation and retirement benefits (26,018) (20,027) (12,013)
Cash collateral, net 97
 2,141
 (4,580)
Pension trust contributions (35,000) —
 (123,521)
Decrease (increase) in operating assets-      
Receivables 51,717
 (424) (32,088)
Prepayments and other current assets (875) 14,057
 (8,948)
Increase (decrease) in operating liabilities-      
Accounts payable (3,548) (18,598) (2,781)
Accrued taxes (44,217) 39,375
 (5,001)
Accrued interest (118) (1,248) 10,607
Other 12,476
 8,026
 4,926
Net cash provided from operating activities 125,468
 278,464
 166,485
       
CASH FLOWS FROM FINANCING ACTIVITIES:      
New financing-      
Long-term debt —
 —
 300,000
Short-term borrowings, net 133,485
 124,079
 —
Redemptions and repayments-      
Common Stock (150,000) —
 —
Long-term debt (13,697) (100,000) —
Short-term borrowings, net —
 —
 (265,003)
Common stock dividend payments (230,000) (30,000) —
Other (1,107) —
 (2,268)
Net cash provided from (used for) financing activities (261,319) (5,921) 32,729
       
CASH FLOWS FROM INVESTING ACTIVITIES:      
Property additions (96,934) (107,230) (100,201)
Sales of investment securities held in trusts 860,080
 460,277
 67,973
Purchases of investment securities held in trusts (868,472) (470,192) (77,738)
Loans to affiliated companies, net 11,028
 86,122
 (85,704)
Other, net (12,914) 1,580
 (3,568)
Net cash used for investing activities (107,212) (29,443) (199,238)
       
Net change in cash and cash equivalents (243,063) 243,100
 (24)
Cash and cash equivalents at beginning of year 243,220
 120
 144
Cash and cash equivalents at end of year $157
 $243,220
 $120
       
SUPPLEMENTAL CASH FLOW INFORMATION:      
Cash paid (received) during the year-      
Interest (net of amounts capitalized) $50,038
 $49,285
 $41,809
Income taxes $79,067
 $(43,227) $(5,801)
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


METROPOLITAN EDISON173


PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
  For the Years Ended December 31,
(In thousands) 2011 2010 2009
STATEMENTS OF INCOME      
REVENUES (Note 17):      
Electric sales $1,026,342
 $1,471,956
 $1,385,574
Gross receipts tax collections 54,852
 67,915
 63,372
Total revenues 1,081,194
 1,539,871
 1,448,946
       
OPERATING EXPENSES (Note 17):      
Purchased power from affiliates 208,183
 643,152
 341,645
Purchased power from non-affiliates 332,279
 364,647
 544,490
Other operating expenses 148,298
 246,966
 192,761
Pensions and OPEB mark-to-market adjustment 41,127
 8,279
 33,983
Provision for depreciation 63,071
 65,694
 65,637
Amortization (deferral) of regulatory assets, net 62,730
 (34,819) 56,572
General taxes 66,001
 73,285
 73,839
Total operating expenses 921,689
 1,367,204
 1,308,927
       
OPERATING INCOME 159,505
 172,667
 140,019
       
OTHER INCOME (EXPENSE) (Note 17):      
Miscellaneous income 2,754
 5,957
 3,662
Interest expense (69,302) (69,864) (54,605)
Capitalized interest 214
 770
 230
Total other expense (66,334) (63,137) (50,713)
       
INCOME BEFORE INCOME TAXES 93,171
 109,530
 89,306
       
INCOME TAXES 30,098
 46,340
 38,508
       
NET INCOME $63,073
 $63,190
 $50,798
       
STATEMENTS OF COMPREHENSIVE INCOME      
       
NET INCOME $63,073
 $63,190
 $50,798
       
OTHER COMPREHENSIVE LOSS:      
Pensions and OPEB prior service costs (27,960) (20,421) (820)
Unrealized gain on derivative hedges 65
 65
 79
Change in unrealized gain on investments —
 —
 (17)
Other comprehensive loss (27,895) (20,356) (758)
Income taxes (benefits) on other comprehensive loss (14,566) (11,794) 4,831
Other comprehensive loss, net of tax (13,329) (8,562) (5,589)
       
COMPREHENSIVE INCOME $49,744
 $54,628
 $45,209
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


For the Years Ended December 31, 2009  2008  2007 
  (In thousands) 
          
REVENUES:         
Electric sales $1,611,088  $1,573,781  $1,437,498 
Gross receipts tax collections  77,894   79,221   73,012 
Total revenues  1,688,982   1,653,002   1,510,510 
             
EXPENSES (Note 18):            
Purchased power from affiliates  365,491   303,779   290,205 
Purchased power from non-affiliates  536,054   593,203   494,284 
Other operating costs  277,024   429,745   419,512 
Provision for depreciation  51,006   44,556   42,798 
Amortization of regulatory assets  129,296   131,542   123,410 
Deferral of new regulatory assets  115,413   (110,038)  (124,821)
General taxes  87,799   85,643   80,135 
Total expenses  1,562,083   1,478,430   1,325,523 
             
OPERATING INCOME  126,899   174,572   184,987 
             
OTHER INCOME (EXPENSE) (Note 18):            
Interest income  9,709   17,647   28,953 
Miscellaneous income (expense)  4,033   105   (339)
Interest expense  (56,683)  (43,651)  (51,022)
Capitalized interest  159   258   1,154 
Total other expense  (42,782)  (25,641)  (21,254)
             
INCOME BEFORE INCOME TAXES  84,117   148,931   163,733 
             
INCOME TAXES  28,594   60,898   68,270 
             
NET INCOME $55,523  $88,033  $95,463 
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

174
177


METROPOLITAN EDISONPENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

As of December 31, 2009  2008 
  (In thousands) 
ASSETS      
CURRENT ASSETS:      
Cash and cash equivalents $120  $144 
Receivables-        
Customers (less accumulated provisions of $4,044,000 and $3,616,000,        
respectively, for uncollectible accounts)  171,052   159,975 
Associated companies  29,413   17,034 
Other  11,650   19,828 
Notes receivable from associated companies  97,150   11,446 
Prepaid taxes  15,229   6,121 
Other  1,459   1,621 
   326,073   216,169 
UTILITY PLANT:        
In service  2,162,815   2,065,847 
Less - Accumulated provision for depreciation  810,746   779,692 
   1,352,069   1,286,155 
Construction work in progress  14,901   32,305 
   1,366,970   1,318,460 
OTHER PROPERTY AND INVESTMENTS:        
Nuclear plant decommissioning trusts  266,479   226,139 
Other  890   976 
   267,369   227,115 
DEFERRED CHARGES AND OTHER ASSETS:        
Goodwill  416,499   416,499 
Regulatory assets  356,754   412,994 
Power purchase contract asset  176,111   300,141 
Other  36,544   31,031 
   985,908   1,160,665 
  $2,946,320  $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  40,521   28,707 
Other  41,050   55,330 
Accrued taxes  11,170   16,238 
Accrued interest  17,362   6,755 
Other  24,520   30,647 
   263,123   431,180 
CAPITALIZATION (See Consolidated Statements of Capitalization):
        
Common stockholder's equity  1,057,918   1,004,064 
Long-term debt and other long-term obligations  713,873   513,752 
   1,771,791   1,517,816 
NONCURRENT LIABILITIES:        
Accumulated deferred income taxes  453,462   387,757 
Accumulated deferred investment tax credits  7,313   7,767 
Nuclear fuel disposal costs  44,391   44,328 
Asset retirement obligations  180,297   170,999 
Retirement benefits  33,605   145,218 
Power purchase contract liability  143,135   150,324 
Other  49,203   67,020 
   911,406   973,413 
COMMITMENTS AND CONTINGENCIES (Notes 7 and 15)        
  $2,946,320  $2,922,409 
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

178
  As of December 31,
(In thousands, except share amounts) 2011 2010
ASSETS    
CURRENT ASSETS:    
Cash and cash equivalents $2
 $5
Receivables-    
Customers, net of allowance for uncollectible accounts of $2,243 in 2011 and $3,369 in 2010 125,979
 148,864
Affiliated companies 18,339
 54,052
Other, net of allowance for uncollectible accounts of $2 in 2011 and $1 in 2010 21,833
 11,314
Notes receivable from affiliated companies —
 14,404
Prepaid taxes 7,065
 14,026
Other 2,406
 1,592
  175,624
 244,257
UTILITY PLANT:    
In service 2,814,374
 2,714,541
Less — Accumulated provision for depreciation 982,265
 955,314
  1,832,109
 1,759,227
Construction work in progress 57,177
 30,505
  1,889,286
 1,789,732
OTHER PROPERTY AND INVESTMENTS:    
Nuclear plant decommissioning trusts 165,921
 152,928
Non-utility generation trusts 95,687
 80,244
Other 288
 297
  261,896
 233,469
DEFERRED CHARGES AND OTHER ASSETS:    
Goodwill 768,628
 768,628
Regulatory assets 209,178
 163,428
Other 17,025
 25,033
  994,831
 957,089
  $3,321,637
 $3,224,547
LIABILITIES AND CAPITALIZATION    
CURRENT LIABILITIES:    
Currently payable long-term debt $45,522
 $45,000
Short-term borrowings - affiliated companies 57,900
 101,338
Accounts payable-    
Affiliated companies 36,602
 35,626
Other 29,423
 41,420
Accrued taxes 9,311
 6,531
Accrued interest 17,455
 17,378
Other 26,045
 22,541
  222,258
 269,834
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 913,443
 913,519
Accumulated other comprehensive income 37,053
 50,382
Accumulated deficit (97,806) (90,879)
Total common stockholder’s equity 941,242
 961,574
Long-term debt and other long-term obligations 1,075,781
 1,072,262
  2,017,023
 2,033,836
NONCURRENT LIABILITIES:    
Accumulated deferred income taxes 498,754
 437,532
Retirement benefits 262,500
 187,621
Asset retirement obligations 104,865
 98,132
Power purchase contract liability 123,031
 116,972
Other 93,206
 80,620
  1,082,356
 920,877
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Notes 6 and 16) 
 
  $3,321,637
 $3,224,547
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


METROPOLITAN EDISON COMPANY175

CONSOLIDATED STATEMENTS OF CAPITALIZATION

As of December 31, 2009  2008 
  (In thousands) 
COMMON STOCKHOLDER'S EQUITY:      
Common stock, without par value, 900,000 shares authorized,      
859,500 shares outstanding $1,197,070  $1,196,172 
Accumulated other comprehensive loss (Note 2(F))  (143,551)  (140,984)
Retained earnings (Accumulated deficit) (Note 12(A))  4,399   (51,124)
Total  1,057,918   1,004,064 
         
         
LONG-TERM DEBT (Note 12(C)):        
First mortgage bonds-        
5.950% due 2027  13,690   13,690 
Total  13,690   13,690 
         
Unsecured notes-        
4.450% due 2010  100,000   100,000 
4.950% due 2013  150,000   150,000 
4.875% due 2014  250,000   250,000 
7.700% due 2019  300,000   - 
  * 0.24% due 2021  28,500   28,500 
Total  828,500   528,500 
         
         
Unamortized premium on debt  183   62 
Long-term debt due within one year  (128,500)  (28,500)
Total long-term debt  713,873   513,752 
TOTAL CAPITALIZATION $1,771,791  $1,517,816 
* Denotes variable rate issue with applicable year-end interest rate shown.
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

179

METROPOLITAN EDISONPENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'SSTOCKHOLDER’S EQUITY

           Accumulated  Retained 
     Common Stock  Other  Earnings 
  Comprehensive  Number  Carrying  Comprehensive  (Accumulated 
  Income (Loss)  of Shares  Value  Income (Loss)  Deficit) 
  (Dollars in thousands) 
                
Balance, January 1, 2007     859,500  $1,276,075  $(26,516) $(234,620)
Net Income $95,463               95,463 
Net unrealized gain on derivative instruments  335           335     
Pension and other postretirement benefits, net                    
of $11,666,000 of income taxes (Note 3)  10,784           10,784     
Comprehensive income $106,582                 
Restricted stock units          104         
Stock-based compensation          7         
Consolidated tax benefit allocation          1,237       - 
Purchase accounting fair value adjustment          (74,237)        
Balance, December 31, 2007      859,500   1,203,186   (15,397)  (139,157)
Net Income $88,033               88,033 
Net unrealized gain on derivative instruments  335           335     
Pension and other postretirement benefits, net                    
of $86,030,000 of income tax benefits (Note 3)  (125,922)          (125,922)    
Comprehensive loss $(37,554)                
Restricted stock units          9         
Stock-based compensation          1         
Consolidated tax benefit allocation          791         
Purchase accounting fair value adjustment          (7,815)        
Balance, December 31, 2008      859,500   1,196,172   (140,984)  (51,124)
Net Income $55,523               55,523 
Net unrealized gain on derivative instruments  335           335     
Pension and other postretirement benefits, net                    
of $2,784,000 of income taxes (Note 3)  (2,902)          (2,902)    
Comprehensive income $52,956                 
Restricted stock units          55         
Consolidated tax benefit allocation          843         
Balance, December 31, 2009      859,500  $1,197,070  $(143,551) $4,399 
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

180
  Common Stock Other Paid-In Capital Accumulated Other Comprehensive Income Accumulated Deficit
(In thousands, except share amounts) Number of Shares Par Value   
Balance, January 1, 2009 4,427,577
 $88,552
 $912,441
 $64,533
 $(64,867)
Net income         50,798
Change in unrealized gain on investments, net of $15 of income tax benefits       (2)  
Change in unrealized loss on derivative instruments, net of $7 of income taxes       72
  
Pensions and OPEB, net of $4,839 of income taxes (Note 3)       (5,659)  
Restricted stock units     65
    
Consolidated tax benefit allocation     931
    
Cash dividends declared on common stock         (50,000)
Balance, December 31, 2009 4,427,577
 88,552
 913,437
 58,944
 (64,069)
Net income         63,190
Change in unrealized loss on derivative instruments, net of $105 of income taxes       (40)  
Pensions and OPEB, net of $11,899 of income tax benefits (Note 3)       (8,522)  
Restricted stock units     82
    
Cash dividends declared on common stock         (90,000)
Balance, December 31, 2010 4,427,577
 88,552
 913,519
 50,382
 (90,879)
Net income         63,073
Change in unrealized loss on derivative instruments, net of $27 of income tax benefits       38
  
Pensions and OPEB, net of $14,593 of income tax benefits (Note 3)       (13,367)  
Restricted stock units     (76)    
Cash dividends declared on common stock         (70,000)
Balance, December 31, 2011 4,427,577
 $88,552
 $913,443
 $37,053
 $(97,806)
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.


METROPOLITAN EDISON176


PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2009  2008  2007 
  (In thousands) 
          
CASH FLOWS FROM OPERATING ACTIVITIES:         
Net income $55,523  $88,033  $95,463 
Adjustments to reconcile net income to net cash from operating activities-            
Provision for depreciation  51,006   44,556   42,798 
Amortization (deferral) of regulatory assets  244,709   21,504   (1,411)
Deferred costs recoverable as regulatory assets  (96,304)  (25,132)  (70,778)
Deferred income taxes and investment tax credits, net  66,965   49,939   35,502 
Accrued compensation and retirement benefits  5,876   (23,244)  (18,852)
Loss on sale of investment  -   -   5,432 
Cash collateral from (to) suppliers  (4,580)  -   1,600 
Pension trust contributions  (123,521)  -   (11,012)
Decrease (increase) in operating assets-            
Receivables  (32,088)  (24,282)  (38,220)
Prepayments and other current assets  (8,948)  8,223   (926)
Increase (decrease) in operating liabilities-            
Accounts payable  (2,781)  (12,512)  (62,760)
Accrued taxes  (5,001)  470   10,128 
Accrued interest  10,607   (23)  (718)
Other  5,022   15,629   12,870 
Net cash provided from (used for) operating activities  166,485   143,161   (884)
             
CASH FLOWS FROM FINANCING ACTIVITIES:            
New Financing-            
Long-term debt  300,000   28,500   - 
Short-term borrowings, net  -   -   143,826 
Redemptions and Repayments-            
Long-term debt  -   (28,568)  (50,000)
Short-term borrowings, net  (265,003)  (20,324)  - 
Other  (2,268)  (266)  (35)
Net cash provided from (used for) financing activities  32,729   (20,658)  93,791 
             
CASH FLOWS FROM INVESTING ACTIVITIES:            
Property additions  (100,201)  (110,301)  (103,711)
Proceeds from sale of investment  -   -   4,953 
Sales of investment securities held in trusts  67,973   181,007   184,619 
Purchases of investment securities held in trusts  (77,738)  (193,061)  (196,140)
Loan repayments from (loans to) associated companies, net  (85,704)  1,128   18,535 
Other  (3,568)  (1,267)  (1,158)
Net cash used for investing activities  (199,238)  (122,494)  (92,902)
             
Net (decrease) increase in cash and cash equivalents  (24)  9   5 
Cash and cash equivalents at beginning of year  144   135   130 
Cash and cash equivalents at end of year $120  $144  $135 
             
SUPPLEMENTAL CASH FLOW INFORMATION:            
Cash Paid (Received) During the Year-            
Interest (net of amounts capitalized) $41,809  $38,627  $44,501 
Income taxes $(5,801) $16,872  $30,741 
  For the Years Ended December 31,
(In thousands) 2011 2010 2009
CASH FLOWS FROM OPERATING ACTIVITIES:      
Net income $63,073
 $63,190
 $50,798
Adjustments to reconcile net income to net cash from operating activities-      
Provision for depreciation 63,071
 65,694
 65,637
Amortization (deferral) of regulatory assets, net 62,730
 (34,819) 56,572
Deferred costs recoverable as regulatory assets (93,790) (89,070) (100,990)
Deferred income taxes and investment tax credits, net 71,832
 139,052
 55,879
Pensions and OPEB mark-to-market adjustment 41,127
 8,279
 33,983
Accrued compensation and retirement benefits (21,051) (13,442) (12,529)
Cash collateral, net 5,110
 (3,980) —
Pension trust contribution —
 —
 (60,000)
Decrease (increase) in operating assets-      
Receivables 52,348
 24,687
 22,891
Prepaid taxes 6,147
 4,728
 (2,519)
Increase (decrease) in operating liabilities-      
Accounts payable (16,865) (5,128) 3,114
Accrued taxes (5,048) (10,089) (6,855)
Accrued interest 76
 (220) 4,467
Other 14,012
 4,860
 3,104
Net cash provided from operating activities 242,772
 153,742
 113,552
       
CASH FLOWS FROM FINANCING ACTIVITIES:      
New financing-      
Long-term debt 25,000
 25,000
 498,583
Short-term borrowings, net —
 59,865
 —
Redemptions and repayments-      
Long-term debt (25,000) (49,310) (135,000)
Short-term borrowings, net (43,438) —
 (239,929)
Common stock dividend payments (70,000) (90,000) (85,000)
Other (1,430) (48) (4,453)
Net cash provided from (used for) financing activities (114,868) (54,493) 34,201
       
CASH FLOWS FROM INVESTING ACTIVITIES:      
Property additions (112,405) (126,344) (124,262)
Loans to affiliated companies, net 14,404
 185
 244
Sales of investment securities held in trusts 450,866
 164,627
 84,400
Purchases of investment securities held in trusts (471,394) (129,714) (98,467)
Other (9,378) (8,012) (9,677)
Net cash used for investing activities (127,907) (99,258) (147,762)
       
Net change in cash and cash equivalents (3) (9) (9)
Cash and cash equivalents at beginning of year 5
 14
 23
Cash and cash equivalents at end of year $2
 $5
 $14
       
SUPPLEMENTAL CASH FLOW INFORMATION:      
Cash paid (received) during the year-      
Interest (net of amounts capitalized) $66,516
 $67,208
 $48,265
Income taxes $(49,275) $(115,870) $(10,775)
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

181

PENNSYLVANIA ELECTRIC COMPANY177

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2009  2008  2007 
  (In thousands) 
          
REVENUES:         
Electric sales $1,385,574  $1,443,461  $1,336,517 
Gross receipts tax collections  63,372   70,168   65,508 
Total revenues  1,448,946   1,513,629   1,402,025 
             
EXPENSES (Note 18):            
Purchased power from affiliates  341,645   284,074   284,826 
Purchased power from non-affiliates  544,490   591,487   505,528 
Other operating costs  209,156   228,257   234,949 
Provision for depreciation  61,317   54,643   49,558 
Amortization of regulatory assets, net  56,572   71,091   46,761 
General taxes  73,839   79,604   76,050 
Total expenses  1,287,019   1,309,156   1,197,672 
             
OPERATING INCOME  161,927   204,473   204,353 
             
OTHER INCOME (EXPENSE):            
Miscellaneous income  3,662   1,359   6,501 
Interest expense (Note 18)  (54,605)  (59,424)  (54,840)
Capitalized interest  98   (591)  939 
Total other expense  (50,845)  (58,656)  (47,400)
             
INCOME BEFORE INCOME TAXES  111,082   145,817   156,953 
             
INCOME TAXES  45,694   57,647   64,015 
             
NET INCOME $65,388  $88,170  $92,938 
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

182

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

As of December 31, 2009  2008 
  (In thousands) 
ASSETS      
CURRENT ASSETS:      
Cash and cash equivalents $14  $23 
Receivables-        
Customers (less accumulated provisions of $3,483,000 and $3,121,000,        
respectively, for uncollectible accounts)  139,302   146,831 
Associated companies  77,338   65,610 
Other  18,320   26,766 
Notes receivable from associated companies  14,589   14,833 
Prepaid taxes  18,946   16,310 
Other  1,400   1,517 
   269,909   271,890 
UTILITY PLANT:        
In service  2,431,737   2,324,879 
Less - Accumulated provision for depreciation  901,990   868,639 
   1,529,747   1,456,240 
Construction work in progress  24,205   25,146 
   1,553,952   1,481,386 
OTHER PROPERTY AND INVESTMENTS:        
Nuclear plant decommissioning trusts  142,603   115,292 
Non-utility generation trusts  120,070   116,687 
Other  289   293 
   262,962   232,272 
DEFERRED CHARGES AND OTHER ASSETS:        
Goodwill  768,628   768,628 
Regulatory assets  9,045   - 
Power purchase contract asset  15,362   119,748 
Other  19,143   18,658 
   812,178   907,034 
  $2,899,001  $2,892,582 
LIABILITIES AND CAPITALIZATION        
CURRENT LIABILITIES:        
Currently payable long-term debt $69,310  $145,000 
Short-term borrowings-        
Associated companies  41,473   31,402 
Other  -   250,000 
Accounts payable-        
Associated companies  39,884   63,692 
Other  41,990   48,633 
Accrued taxes  6,409   13,264 
Accrued interest  17,598   13,131 
Other  22,741   31,730 
   239,405   596,852 
CAPITALIZATION (See Consolidated Statements of Capitalization):
        
Common stockholder's equity  931,386   949,109 
Long-term debt and other long-term obligations  1,072,181   633,132 
   2,003,567   1,582,241 
NONCURRENT LIABILITIES:        
Regulatory liabilities  -   136,579 
Accumulated deferred income taxes  242,040   169,807 
Retirement benefits  174,306   172,718 
Asset retirement obligations  91,841   87,089 
Power purchase contract liability  100,849   83,600 
Other  46,993   63,696 
   656,029   713,489 
COMMITMENTS AND CONTINGENCIES (Notes 7 and 15)        
  $2,899,001  $2,892,582 
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

183

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION

As of December 31, 2009  2008 
  (In thousands) 
COMMON STOCKHOLDER'S EQUITY:      
Common stock, $20 par value, 5,400,000 shares authorized,      
4,427,577 shares outstanding $88,552  $88,552 
Other paid-in capital  913,437   912,441 
Accumulated other comprehensive income (loss) (Note 2(F))  (162,104)  (127,997)
Retained earnings (Note 12(A))  91,501   76,113 
Total  931,386   949,109 
         
         
LONG-TERM DEBT (Note 12(C)):        
First mortgage bonds-        
5.350% due 2010  12,310   12,310 
5.350% due 2010  12,000   12,000 
Total  24,310   24,310 
         
Unsecured notes-        
6.125% due 2009  -   100,000 
7.770% due 2010  -   35,000 
5.125% due 2014  150,000   150,000 
6.050% due 2017  300,000   300,000 
6.625% due 2019  125,000   125,000 
  * 0.240% due 2020  20,000   20,000 
5.200% due 2020  250,000   - 
  * 0.340% due 2025  25,000   25,000 
6.150% due 2038  250,000   - 
Total  1,120,000   755,000 
         
         
Net unamortized discount on debt  (2,819)  (1,178)
Long-term debt due within one year  (69,310)  (145,000)
Total long-term debt  1,072,181   633,132 
TOTAL CAPITALIZATION $2,003,567  $1,582,241 
* Denotes variable rate issue with applicable year-end interest rate shown.
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

184

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

              Accumulated    
     Common Stock  Other  Other    
  Comprehensive  Number  Par  Paid-In  Comprehensive  Retained 
  Income (Loss)  of Shares  Value  Capital  Income (Loss)  Earnings 
  (Dollars in thousands) 
                   
Balance, January 1, 2007    $5,290,596  $105,812  $1,189,434  $(7,193) $90,005 
Net income $92,938                   92,938 
Net unrealized gain on investments, net                        
 of $12,000 of income tax benefits  21               21     
Net unrealized gain on derivative instruments, net                        
of $16,000 of income taxes  49               49     
Pension and other postretirement benefits, net                        
of $15,413,000 of income taxes (Note 3)  12,069               12,069     
Comprehensive income $105,077                     
Restricted stock units              107         
Stock-based compensation              7         
Consolidated tax benefit allocation              1,261         
Repurchase of common stock      (863,019)  (17,260)  (182,740)        
Cash dividends declared on common stock                      (125,000)
Purchase accounting fair value adjustment              (87,453)        
Balance, December 31, 2007      4,427,577   88,552   920,616   4,946   57,943 
Net income $88,170                   88,170 
Net unrealized gain on investments, net  9               9     
of $13,000 of income taxes                        
Net unrealized gain on derivative instruments, net  69               69     
of $4,000 of income tax benefits                        
Pension and other postretirement benefits, net                        
of $90,822,000 of income tax benefits (Note 3)  (133,021)              (133,021)    
Comprehensive loss $(44,773)                    
Restricted stock units              35         
Stock-based compensation              1         
Consolidated tax benefit allocation              1,066         
Cash dividends declared on common stock                      (70,000)
Purchase accounting fair value adjustment              (9,277)        
Balance, December 31, 2008      4,427,577  $88,552  $912,441  $(127,997) $76,113 
Net income $65,388                   65,388 
Change in unrealized gain on investments, net  (2)              (2)    
of $15,000 of income taxes                        
Net unrealized gain on derivative instruments, net  72               72     
of $7,000 of income tax benefits                        
Pension and other postretirement benefits, net                        
of $17,244,000 of income tax benefits (Note 3)  (34,177)              (34,177)    
Comprehensive income $31,281                     
Restricted stock units              65         
Consolidated tax benefit allocation              931         
Cash dividends declared on common stock                      (50,000)
Balance, December 31, 2009      4,427,577  $88,552  $913,437  $(162,104) $91,501 
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

185

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2009  2008  2007 
  (In thousands) 
          
CASH FLOWS FROM OPERATING ACTIVITIES:         
Net income $65,388  $88,170  $92,938 
Adjustments to reconcile net income to net cash from operating activities-            
Provision for depreciation  61,317   54,643   49,558 
Amortization of regulatory assets, net  56,572   71,091   46,761 
Deferred costs recoverable as regulatory assets  (100,990)  (35,898)  (71,939)
Deferred income taxes and investment tax credits, net  63,065   95,227   10,713 
Accrued compensation and retirement benefits  3,866   (25,661)  (20,830)
Pension trust contribution  (60,000)  -   (13,436)
Decrease (increase) in operating assets-            
Receivables  22,891   (74,338)  18,771 
Prepayments and other current assets  (2,519)  (16,313)  1,159 
Increase (decrease) in operating liabilities-            
Accounts payable  3,114   (1,966)  (59,513)
Accrued taxes  (6,855)  (2,181)  4,743 
Accrued interest  4,467   (36)  5,943 
Other  3,236   17,815   13,125 
Net cash provided from operating activities  113,552   170,553   77,993 
             
CASH FLOWS FROM FINANCING ACTIVITIES:            
New Financing-            
Long-term debt  498,583   45,000   299,109 
Short-term borrowings, net  -   66,509   15,662 
Redemptions and Repayments-            
Common Stock  -   -   (200,000)
Long-term debt  (135,000)  (45,556)  - 
Short-term borrowings, net  (239,929)  -   - 
Dividend Payments-            
Common stock  (85,000)  (90,000)  (70,000)
Other  (4,453)  -   (2,210)
Net cash provided from (used for) financing activities  34,201   (24,047)  42,561 
             
CASH FLOWS FROM INVESTING ACTIVITIES:            
Property additions  (124,262)  (126,672)  (94,991)
Loan repayments from associated companies, net  244   1,480   3,235 
Sales of investment securities held in trusts  84,400   117,751   175,222 
Purchases of investment securities held in trusts  (98,467)  (134,621)  (199,375)
Other, net  (9,677)  (4,467)  (4,643)
Net cash used for investing activities  (147,762)  (146,529)  (120,552)
             
Net increase (decrease) in cash and cash equivalents  (9)  (23)  2 
Cash and cash equivalents at beginning of year  23   46   44 
Cash and cash equivalents at end of year $14  $23  $46 
             
SUPPLEMENTAL CASH FLOW INFORMATION:            
Cash Paid (Received) During the Year-            
Interest (net of amounts capitalized) $48,265  $56,972  $44,503 
Income taxes $(10,775) $44,197  $2,996 
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

186
COMBINED NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Note Number
 
Page Number
   
1
Organization, Basis of Presentation and Significant Accounting Policies
179
   
2
Merger
193
   
3
Pension and Other Postemployment Benefits
196
   
4
Stock-Based Compensation Plans
202
   
5
Taxes
205
   
6Leases
211
   
7Intangible Assets
213
   
8
Variable Interest Entities
213
   
9
Fair Value Measurements
215
   
10Derivatives
224
   
11Impairment of Long-Lived Assets
228
   
12Capitalization
229
   
13Short-Term Borrowings and Bank Lines of Credit
233
   
14
Asset Retirement Obligations
235
   
15
Regulatory Matters
236
   
16
Commitments, Guarantees and Contingencies
245
   
17Transactions With Affiliated Companies
254
   
18
Supplemental Guarantor Information
255
   
19
Segment Information
264
   
20Summary of Quarterly Financial Data (Unaudited)
267


178


1. ORGANIZATION, AND BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

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, AE and its principal subsidiaries (AE Supply, AGC, MP, PE, WP, TrAIL and AESC), FES and its principal subsidiaries FGCO(FGCO and NGC,NGC), and FESC.

AE merged with a subsidiary of FE on February 25, 2011, with AE continuing as the surviving corporation and becoming a wholly owned subsidiary of FE (See Note 2, Merger).
FirstEnergy and its subsidiaries followfollows GAAP and complycomplies with the related regulations, orders, policies and practices prescribed by the SEC, FERC, and, as applicable, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC, the VSCC 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, FirstEnergyFE and its subsidiaries have evaluated events and transactions for potential recognition or disclosure through February 18, 2010, the date the financial statements were issued.

FirstEnergyFE 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 unless otherwise prescribed by GAAP (see Note 16). FirstEnergy consolidatesconsolidation. FE and its subsidiaries consolidate a VIE (see Note 8) when it is determined to bethat it is the VIE's primary beneficiary.beneficiary (see Note 8, Variable Interest Entities). Investments in non-consolidated affiliates over which FirstEnergyFE and its subsidiaries have the ability to exercise significant influence, but with respect to which they are not the primary beneficiary and do not exercise control, (20-50% owned companies, joint ventures and partnerships) are accounted for underfollow the equity method.method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage share of the entity’s earnings is reported in the Consolidated Statements of Income and Comprehensive Income. These footnotes combine results of FE,Notes to the Consolidated Financial Statements are combined for FirstEnergy, FES, OE, CEI, TE JCP&L, Met-Ed and Penelec.

Certain prior year amounts have been reclassified to conform to the current year presentation.presentation, and the effects of the change in accounting for pensions and OPEB costs described further below have been retrospectively applied to all periods presented. Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.

2.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(A)    ACCOUNTING FOR THE EFFECTS OF REGULATION

FirstEnergy accounts for the effects of regulation through the application of regulatory accounting to its operating utilities since their rates:

·rates are established by a third-party regulator with the authority to set rates that bind customers;

·are cost-based; and

·can be charged to and collected from customers.

An enterprise meeting all of these criteria capitalizes costs that would otherwisebind customers, are cost-based and can be charged to expense (regulatory assets) ifand collected from customers.
FirstEnergy records regulatory assets and liabilities that result from the rate actionsregulated rate-making process that would not be recorded under GAAP for non-regulated entities. These assets and liabilities are amortized in the Consolidated Statements of its regulator makeIncome concurrent with the recovery or refund through customer rates. FirstEnergy believes that it is probable that those costsits regulatory assets and liabilities will be recovered inand settled, respectively, through future revenue. Regulatory accounting is applied only torates. FirstEnergy and the parts of the business that meet the above criteria. If a portion of the business applying regulatory accounting no longer meets those requirements, previously recordedUtilities net their regulatory assets are removed from the balance sheet in accordance with GAAP.and liabilities based on federal and state jurisdictions.


179
187


RegulatoryNet regulatory assets on FirstEnergy's and the Utility Registrants' Consolidated Balance Sheets are comprised of the following:

Regulatory Assets
 FE  OE  CEI  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
December 31, 2009
                     
Regulatory transition costs
 $1,100  $73  $8  $8  $965  $116  $(70)
Customer shopping incentives
  154   -   154   -   -   -   - 
Customer receivables for future income taxes
  329   58   3   1   31   114   122 
Loss (Gain) on reacquired debt
  51   18   1   (3)  22   8   5 
Employee postretirement benefit costs
  23   -   5   2   10   6   - 
Nuclear decommissioning, decontamination
                            
and spent fuel disposal costs
  (162)  -   -   -   (22)  (83)  (57)
Asset removal costs
  (231)  (23)  (43)  (17)  (148)  -   - 
MISO/PJM transmission costs
  148   (15)  (15)  (3)  -   187   (6)
Fuel costs
  369   115   222   32   -   -   - 
Distribution costs
  482   230   197   55   -   -   - 
Other
  93   9   14   (5)  30   9   15 
Total
 $2,356  $465  $546  $70  $888  $357  $9 
                             
December 31, 2008*
                            
Regulatory transition costs
 $1,452  $112  $80  $12  $1,236  $12  $- 
Customer shopping incentives
  420   -   420   -   -   -   - 
Customer receivables for future income taxes
  245   68   4   1   59   113   - 
Loss (Gain) on reacquired debt
  51   20   1   (3)  24   9   - 
Employee postretirement benefit costs
  31   -   7   3   13   8   - 
Nuclear decommissioning, decontamination
                            
and spent fuel disposal costs
  (57)  -   -   -   (2)  (55)  - 
Asset removal costs
  (215)  (15)  (36)  (16)  (148)  -   - 
MISO/PJM transmission costs
  389   31   19   20   -   319   - 
Fuel costs
  214   109   75   30   -   -   - 
Distribution costs
  475   222   198   55   -   -   - 
Other
  135   28   16   7   46   7   - 
Total
 $3,140  $575  $784  $109  $1,228  $413  $- 
Regulatory Assets (Liabilities) FirstEnergy OE CEI TE JCP&L Met-Ed Penelec
  (In millions)
December 31, 2011              
Regulatory transition costs $608
 $—
 $—
 $—
 $424
 $105
 $79
Customer receivables for future income taxes 508
 42
 1
 2
 29
 129
 145
Nuclear decommissioning, decontamination and spent fuel disposal costs (210) —
 —
 —
 (44) (99) (67)
Asset removal costs (240) (34) (60) (23) (147) —
 —
PJM transmission costs 340
 (3) (3) (1) —
 181
 63
Deferred generation costs 382
 125
 224
 37
 —
 (23) (11)
Distribution costs 267
 146
 73
 48
 —
 —
 —
Other 375
 87
 60
 7
 146
 36
 —
Net regulatory assets $2,030
 $363
 $295
 $70
 $408
 $329
 $209
               
December 31, 2010              
Regulatory transition costs $770
 $—
 $—
 $—
 $591
 $131
 $43
Customer receivables for future income taxes 328
 52
 2
 1
 30
 113
 130
Nuclear decommissioning, decontamination and spent fuel disposal costs (184) —
 —
 —
 (31) (92) (61)
Asset removal costs (237) (24) (47) (19) (147) —
 —
PJM transmission costs 183
 —
 —
 —
 —
 131
 52
Deferred generation costs 386
 125
 226
 35
 —
 —
 —
Distribution costs 426
 216
 155
 55
 —
 —
 —
Other 158
 34
 34
 1
 71
 13
 (1)
Net regulatory assets $1,830
 $403
 $370
 $73
 $514
 $296
 $163

*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.
Additionally, FirstEnergy had $381 million of net regulatory liabilities as of December 31, 2011, including $366 million of net regulatory liabilities attributable to Allegheny that are primarily related to asset removal costs. Net regulatory liabilities are classified within Other Noncurrent Liabilities on the Consolidated Balance Sheets.

Regulatory assets that do not earn a current return (primarily foras of December 31, 2011 totaled approximately $413 million. Regulatory assets that do not earn a return are primarily comprised of certain regulatory transition and PJM transmission costs and employee postretirement benefits) totaled approximately $187 million as of December 31, 2009 (JCP&L - $36 million,for Met-Ed - $114 million, and Penelec - $37 million). Regulatory assets not earning a current return willof $182 million and $115 million, respectively, that are expected to be recovered by 2014 for2020, and certain storm damage costs and pension and OPEB costs incurred by JCP&L andof $122 million that are expected to be recovered by 2020 for Met-Ed and Penelec.2026.

Transition Cost Amortization

JCP&L’s and Met-Ed’s regulatory transition costs include the deferral of above-market costs for power supplied from NUGs of $369$142 million for JCP&L (recovered through NGC revenues) and $110$105 million for Met-Ed (recovered through CTC revenues). Projected above-market NUG costs are adjusted to fair value at the end of each quarter, with a corresponding offset to regulatory assets. Recovery of the remaining regulatory transition costs is expected to continue pursuant to various regulatory proceedings in New Jersey and Pennsylvania (see Note 11)15, Regulatory Matters).

(B)REVENUES AND RECEIVABLES

The Utilities' principal business is providing electric service to customers in Ohio, Pennsylvania, West Virginia, New Jersey and New Jersey.Maryland. The Utilities'Utilities’ retail customers are metered on a cycle basis. FES' and AE Supply's principal business is supplying electric power to end-use customers through retail and wholesale arrangements, including affiliated company power sales to meet a portion of the POLR and default service requirements of the Ohio and Pennsylvania Companies and competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland.
Electric revenues are recorded based on energy delivered through the end of the calendar month. An estimate of unbilled revenues is calculated to recognize electric service provided from the last meter reading through the end of the month. This estimate includes many factors, among which are historical customer usage, load profiles, estimated weather impacts, customer shopping activity and prices in effect for each class of customer. In each accounting period, the Utilities, FES and AE Supply accrue the estimated unbilled amount receivable as revenue and reverse the related prior period estimate.


180
188


Receivables from customers include distribution and retail electric sales to residential, commercial and industrial customers for the Utilities, and retail and wholesale sales to wholesale customers.customers for FES and AE Supply. There was were no material concentration of receivables as of December 31, 20092011 and 2010 with respect to any particular segment of FirstEnergy'sFirstEnergy’s customers. Billed and unbilled customer receivables as of December 31, 20092011 and 20082010 are shown below.

Customer Receivables FE  FES  OE  CEI  
TE(1)
  JCP&L  Met-Ed  Penelec  FirstEnergy FES OE CEI 
TE(1)
 JCP&L Met-Ed Penelec
December 31, 2009                        
 (In millions)
December 31, 2011                
Billed $725  $109  $101  $114  $1  $183  $110  $88  $800
 $220
 $67
 $40
 $24
 $117
 $79
 $72
Unbilled  519   86   108   95   -   118   61   51  725
 204
 96
 52
 25
 118
 60
 54
Total $1,244  $195  $209  $209  $1  $301  $171  $139  $1,525
 $424
 $163
 $92
 $49
 $235
 $139
 $126
December 31, 2008                                
December 31, 2010                
Billed $752  $84  $143  $150  $1  $179  $93  $86  $752
 $196
 $81
 $95
 $—
 $178
 $101
 $82
Unbilled  552   2   134   126   -   161   67   61  640
 170
 96
 89
 —
 145
 78
 67
Total $1,304  $86  $277  $276  $1  $340  $160  $147  $1,392
 $366
 $177
 $184
 $—
 $323
 $179
 $149
(1)See Note 14 for a discussion of TE’s
(1)
During 2011, TE's accounts receivable financing arrangement with Centerior Funding Corporation.Corporation was terminated.
(C)EARNINGS PER SHARE OF COMMON STOCK

Basic earnings per share of common stock isare computed using the weighted average number of actual common shares outstanding during the respectiverelevant 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. In 2007, FirstEnergy repurchased approximately 14.4 million shares, or 4.5%, of its outstanding common stock for $951 million through an accelerated share repurchase program.  The following table reconciles basic and diluted earnings per share of common stock:

Reconciliation of Basic and Diluted         
Earnings per Share of Common Stock 2009  2008  2007 
  (In millions, except per share amounts) 
          
Earnings available to FirstEnergy Corp. $1,006  $1,342  $1,309 
             
Average shares of common stock outstanding – Basic  304   304   306 
Assumed exercise of dilutive stock options and awards  2   3   4 
Average shares of common stock outstanding – Diluted  306   307   310 
             
Basic earnings per share of common stock: $3.31  $4.41  $4.27 
Diluted earnings per share of common stock: $3.29  $4.38  $4.22 
Reconciliation of Basic and Diluted Earnings per Share of Common Stock 2011 2010 2009
  (In millions, except per share amounts)
Weighted average number of basic shares outstanding(1)
 399
 304
 304
Assumed exercise of dilutive stock options and awards(2)
 2
 1
 2
Weighted average number of diluted shares outstanding(1)
 401
 305
 306
       
Earnings available to FirstEnergy Corp. $885
 $742
 $872
       
Basic earnings per share of common stock $2.22
 $2.44
 $2.87
Diluted earnings per share of common stock $2.21
 $2.42
 $2.85

(D)
(1)
PROPERTY, PLANT AND EQUIPMENT
Includes 113 million shares issued to AE shareholders for the periods subsequent to the merger date (see Note 2, Merger).
(2)
The number of potentially dilutive securities not included in the calculation of diluted shares outstanding due to their antidilutive effect were not significant for the years ending December 31, 2011, 2010 or 2009.
PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment reflects original cost (except for nuclear generating assets which were adjusted to fair value)(net of any impairments recognized), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs incurred to place the assets in service. The costs of normal maintenance, repairs and minor replacements are expensed as incurred. FirstEnergy'sFirstEnergy recognizes liabilities for planned major maintenance projects as they are incurred. Property, plant and equipment balances as of December 31, 20092011 and 20082010 were as follows:

 December 31, 2009 December 31, 2008  December 31, 2011 December 31, 2010
Property, Plant and Equipment Unregulated Regulated Total Unregulated Regulated Total  Unregulated Regulated Total Unregulated Regulated Total
 (In millions)  (In millions)
In service $10,935  $16,891  $27,826  $10,236  $16,246  $26,482  $15,472
 $24,650
 $40,122
 $12,104
 $18,172
 $30,276
Less accumulated depreciation  (4,699)  (6,698)  (11,397)  (4,403)  (6,418)  (10,821)
Less - Accumulated depreciation (4,424) (7,415) (11,839) (4,255) (7,028) (11,283)
Net plant in service $6,236  $10,193  $16,429  $5,833  $9,828  $15,661  $11,048
 $17,235
 $28,283
 $7,849
 $11,144
 $18,993

FirstEnergy provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The respective annual composite rates for FirstEnergy’s subsidiaries’ electric plant in 2009, 2008,2011, 2010 and 20072009 are shown in the following table:


181


189
  Annual Composite Depreciation Rate
  2011 2010 2009
FGCO 3.1% 4.0% 4.6%
NGC 3.2% 3.1% 3.0%
OE 2.9% 2.9% 3.1%
CEI 3.2% 3.2% 3.3%
TE 3.2% 3.3% 3.3%
JCP&L 2.8% 2.4% 2.4%
Met-Ed 2.5% 2.5% 2.5%
Penelec 2.3% 2.5% 2.6%
ATSI 2.4% 2.4%—2.4%
Penn 2.2% 2.2% 2.4%
AE Supply 3.4%    
MP 2.5%    
PE 2.8%    
WP 2.5%    
TrAIL 2.7%    
Jointly Owned Plants

  Annual Composite 
  Depreciation Rate 
  2009  2008  2007 
OE
  3.1%  3.1%  2.9%
CEI
  3.3   3.5   3.6 
TE
  3.3   3.6   3.9 
Penn
  2.4   2.4   2.3 
JCP&L
  2.4   2.3   2.1 
Met-Ed
  2.5   2.3   2.3 
Penelec
  2.6   2.5   2.3 
FGCO
  4.6   4.7   4.0 
NGC
  3.0   2.8   2.8 

FirstEnergy, through its subsidiary, AGC, owns an undivided 40% interest (1,109 MWs) in a 2,773 MW pumped storage, hydroelectric station in Bath County, Virginia, operated by the 60% owner, Virginia Electric and Power Company, a non-affiliated utility. Net Property, Plant and Equipment includes $468 million relating to this facility as of December 31, 2011.
Asset Retirement Obligations

FirstEnergy recognizes an ARO for the future decommissioning of its nuclear power plants and future remediation of other environmental liabilities associated with all of its long-lived assets. The ARO liability represents an estimate of the fair value of FirstEnergy’s current obligation related to nuclear decommissioning and the retirement or remediation of environmental liabilities of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. FirstEnergy uses an expected cash flow approach to measure the fair value of the nuclear decommissioning and environmental remediation ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plant’s current license, settlement based on an extended license term and expected remediation dates. The fair value of an ARO is recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and are depreciated over the life of the related asset, as described further in Note 13.asset.

(E)ASSET IMPAIRMENTS

Long-lived Assets

FirstEnergy reviews long-lived assets, including regulatory assets, for impairment whenever events or changes in circumstances indicate that the carrying amount of such an asset may not be recoverable. The recoverability of the long-lived asset is measured by comparing the long-lived asset’s carrying value to the sum of undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is greater than the undiscounted future cash flows of the long-lived asset, an impairment exists and a loss is recognized for the amount by which the carrying value of the long-lived asset exceeds its estimated fair value.

Impairments of long-lived assets recognized for the year endedDecember 31, 2011, are described further in Note 11, Impairment of Long-Lived Assets.
Goodwill

In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by accounting standards for the recognition and subsequent measurement of goodwill, we evaluate goodwillGoodwill is evaluated for impairment at least annually and make such evaluations more frequently if indicators of impairment arise. IfIn accordance with the accounting standards, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If impairmentImpairment is indicated and a loss is recognized– calculated as the difference betweenrecognized if the implied fair value of a reporting unit's goodwill andis less than the carrying value of theits goodwill.
With the completion of the AE merger in the first quarter of 2011, FirstEnergy reorganized its management structure, which resulted in changes to its operating segments (see Note 19, Segment Information). FirstEnergy's goodwill from the merger of $866 million was assigned to the Competitive Energy Services segment based on expected synergies from the merger. FirstEnergy's reporting


The forecasts used in FirstEnergy's evaluations of goodwill reflect operations182


units are consistent with its general business assumptions. Unanticipatedoperating segments, and consist of Regulated Distribution, Regulated Independent Transmission and Competitive Energy Services. Goodwill is allocated to these operating segments based on the original purchase price allocation for acquisitions within the various reporting units. As of December 31, 2011, goodwill balances for Regulated Distribution and Competitive Energy Services were $5,551 million and $890 million, respectively. No goodwill has been allocated to the Regulated Independent Transmission segment.
Annual impairment testing is conducted during the third quarter of each year and for 2011 and 2010 the analysis indicated no impairment of goodwill. For purposes of annual testing the estimated fair values of Regulated Distribution and Competitive Energy Services were determined using a discounted cash flow approach.
The discounted cash flow model of the Regulated Distribution and Competitive Energy Services segments reporting units is based on the forecasted operating cash flow for the current year, projected operating cash flows (determined using forecasted amounts as well as an estimated growth rate) and a terminal value. Discounted cash flows consist of the operating cash flows for each reporting unit less an estimate for capital expenditures. The key assumptions incorporated in the discounted cash flow approach include growth rates, projected operating income, changes in thoseworking capital, projected capital expenditures, planned funding of pension plans, anticipated funding of nuclear decommissioning trusts, expected results of future rate proceedings (applicable to Regulated Distribution segment only) and a discount rate equal to assumed long-term cost of capital. Cash flows may be adjusted to exclude certain non-recurring or unusual items. Reporting unit income was the starting point for determining operating cash flow and there were no non-recurring or unusual items excluded from the calculations of operating cash flow in any of the periods included in the determination of fair value.
This approach involves management judgment and estimates that are used in relation to changing market conditions and business environment; unanticipated changes in assumptions could have a significant effect on FirstEnergy's future evaluationsevaluation of goodwill. FirstEnergy's goodwill primarily relatesAt the time FirstEnergy conducted the annual impairment testing in 2011, fair value would have to its energy delivery services segment.

FirstEnergy’s 2009 annual review was completed ashave declined in excess of July 31, with no impairment indicated.

FirstEnergy’s 2008 annual review was completed in the third quarter of 2008 with no impairment indicated. Due to the significant downturn in the U.S. economy during the fourth quarter of 2008, goodwill was tested for impairment as of December 31, 2008. No impairment was indicated44% and 53% for the former GPU companies. As discussedRegulated Distribution and Competitive Energy Services segments, respectively, to indicate a potential goodwill impairment. Fair value would have to have declined by more than 20% for CEI, 16% for TE, 38% for JCP&L, 62% for Met-Ed, 58% for Penelec and 62% for FES to indicate a potential goodwill impairment.
Total goodwill recognized by segment in Note 11(B) on February 19, 2009, the Ohio Companies filed an application for an amended ESP, which substantially reflected terms proposedFirstEnergy's Consolidated Balance Sheet is as follows:
Goodwill Regulated Distribution Competitive Energy Services Regulated Independent Transmission Other/Corporate Consolidated
Balance as of December 31, 2010 $5,551
 $24
 $—
 $—
 $5,575
Merger with Allegheny —
 866
 —
 —
 866
Balance as of December 31, 2011 $5,551
 $890
 $—
 $—
 $6,441
Total goodwill recognized by the PUCO Staff on February 2, 2009. Goodwill for the Ohio Companies was tested as of December 31, 2008, reflecting the projected results associated with the amended ESP. No impairment was indicated for the Ohio Companies. The PUCO’s final decision did not result in an additional impairment charge. During 2008, FirstEnergy adjusted goodwill of the former GPU companies by $32 million due to the realization of tax benefits that had been reserved under purchase accounting.

In 2007, FirstEnergy adjusted goodwill for the former GPU companies by $290 million due to the realization of tax benefits that had been reserved in purchase accounting.

190

A summary of the changes in goodwill for the three years ended December 31, 2009 is shown below by operating segment, which represent aggregated reporting units (see Note 16 - Segment Information):

         
 Energy Competitive     
 Delivery Energy     
 Services Services Other Consolidated 
   (In millions)   
Balance as of January 1, 2007
 $5,873  $24  $1  $5,898 
Adjustments related to GPU acquisition
  (290)  -   -   (290)
Other
  -   -   (1)  (1)
Balance as of December 31, 2007
  5,583   24   -   5,607 
Adjustments related to GPU acquisition
  (32)  -   -   (32)
Balance as of December 31, 2008 and 2009
 $5,551  $24  $-  $5,575 

A summary of the changes in FES’FES and the Utilities’ goodwill for the three years ended December 31, 2009 is shown below.Utility Registrants are as follows:

Goodwill FES  CEI  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
Balance as of January 1, 2007
 $24  $1,689  $501  $1,962  $496  $861 
Adjustments related to GPU acquisition
  -   -   -   (136)  (72)  (83)
Balance as of December 31, 2007
  24   1,689   501   1,826   424   778 
Adjustments related to GPU acquisition
  -   -   -   (15)  (8)  (9)
Balance as of December 31, 2008 and 2009
 $24  $1,689  $501  $1,811  $416  $769 
Goodwill FES CEI TE JCP&L Met-Ed Penelec
Balance as of December 31, 2011 and 2010 $24
 $1,689
 $501
 $1,811
 $416
 $769

FirstEnergy, FES and the Utilities,Utility Registrants, with the exception of Met-Ed, as noted below, have no accumulated impairment charge as of December 31, 2009.2011. Met-Ed has an accumulated impairment charge of $355$355 million, which was recorded in 2006.

Investments

At the end of each reporting period, FirstEnergy evaluates its investments for impairment. Investments classified as available-for-sale securities are evaluated to determine whether a decline in fair value below the cost basis is other than temporary. FirstEnergy first considers its intent and ability to hold the investment until recovery and then considers, among other factors, the duration and the extent to which the security'ssecurity’s fair value has been less than its cost and the near-term financial prospects of the security issuer when evaluating investments for impairment. If the decline in fair value is determined to be other than temporary, the cost basis of the investment is written down to fair value. FirstEnergy recognizes in earnings the unrealized losses on available-for-sale securities held in its nuclear decommissioning trusts since the trust arrangements, as they are currently defined, do not meet the required ability and intent to hold criteria in consideration of other-than-temporary impairment. In 2009, 20082011, 2010 and 2007,2009, FirstEnergy recognized $62$19 million $123, $33 million and $26$62 million, respectively, of other-than-temporary impairments. The fair valuevalues of FirstEnergy’s investments are disclosed in Note 5(B).9, Fair Value Measurements.

(F)ACCUMULATED OTHER COMPREHENSIVE INCOME

Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholders' equity except those resulting from transactions with stockholders and adjustments relating to noncontrolling interests. Accumulated other comprehensive income (loss),AOCI, net of tax, included on FE's, FES'FirstEnergy’s, FES’ and the Utilities'Utility Registrants’ Consolidated Balance Sheets as of December 31, 20092011 and 2008,2010, is comprised of the following:


Accumulated Other Comprehensive Income (Loss) FE  FES  OE  CEI  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
Net liability for unfunded retirement benefits $(1,341) $(91) $(164) $(138) $(50) $(242) $(143) $(162)
Unrealized gain on investments  2   2   -   -   -   -   -   - 
Unrealized loss on derivative hedges  (76)  (14)  -   -   -   (1)  (1)  - 
AOCL Balance, December 31, 2009 $(1,415) $(103) $(164) $(138) $(50) $(243) $(144) $(162)
                                 
Net liability for unfunded retirement benefits $(1,322) $(97) $(190) $(135) $(43) $(215) $(140) $(128)
Unrealized gain on investments  45   30   6   -   10   -   -   - 
Unrealized loss on derivative hedges  (103)  (25)  -   -   -   (2)  (1)  - 
AOCL Balance, December 31, 2008 $(1,380) $(92) $(184) $(135) $(33) $(217) $(141) $(128)
183


191
Accumulated Other Comprehensive Income FirstEnergy FES OE CEI TE JCP&L Met-Ed Penelec
  (In millions)
Net liability for unfunded retirement benefits $446
 $52
 $54
 $27
 $12
 $40
 $28
 $37
Unrealized gain on investments 19
 16
 —
 —
 3
 —
 —
 —
Unrealized gain (loss) on derivative hedges (39) 8
 —
 —
 —
 (1) —
 —
Balance, December 31, 2011 $426
 $76
 $54
 $27
 $15
 $39
 $28
 $37
                 
Net liability for unfunded retirement benefits $472
 $55
 $82
 $34
 $15
 $52
 $38
 $50
Unrealized gain on investments 7
 6
 —
 —
 —
 —
 —
 —
Unrealized gain (loss) on derivative hedges (54) 1
 —
 —
 —
 (1) (1) —
Balance, December 31, 2010 $425
 $62
 $82
 $34
 $15
 $51
 $37
 $50

Other comprehensive income (loss)OCI reclassified to net income during the three years ended December 31, 2009, 20082011, 2010 and 20072009 is shown in the following table.
  FirstEnergy FES OE CEI TE JCP&L Met-Ed Penelec
  (In millions)
2011                
Pensions and OPEB $169
 $18
 $28
 $12
 $5
 $25
 $17
 $23
Gain on investments 157
 51
 6
 —
 2
 27
 49
 23
Loss on derivative hedges (26) (26) —
 —
 —
 —
 —
 —
  300
 43
 34
 12
 7
 52
 66
 46
Income taxes related to reclassification to net income 118
 16
 12
 4
 3
 21
 27
 19
Reclassification to net income $182
 $27
 $22
 $8
 $4
 $31
 $39
 $27
2010                
Pensions and OPEB $87
 $46
 $23
 $2
 $3
 $5
 $8
 $15
Gain on investments 54
 50
 2
 —
 2
 —
 —
 —
Loss on derivative hedges (35) (24) —
 —
 —
 —
 —
 —
  106
 72
 25
 2
 5
 5
 8
 15
Income taxes related to reclassification to net income 40
 26
 9
 —
 2
 3
 3
 6
Reclassification to net income $66
 $46
 $16
 $2
 $3
 $2
 $5
 $9
2009                
Pensions and OPEB $68
 $37
 $17
 $2
 $4
 $8
 $7
 $12
Gain on investments 157
 139
 10
 —
 7
 —
 —
 —
Loss on derivative hedges (67) (27) —
 —
 —
 —
 —
 —
  158
 149
 27
 2
 11
 8
 7
 12
Income taxes related to reclassification to net income 60
 56
 10
 1
 4
 3
 3
 5
Reclassification to net income $98
 $93
 $17
 $1
 $7
 $5
 $4
 $7
NEW ACCOUNTING PRONOUNCEMENTS
During the year, there have been various new accounting pronouncements that are not expected to have a material effect on FirstEnergy's financial statements.
CHANGE IN PENSIONS AND OPEB ACCOUNTING POLICY
Effective in 2011, FirstEnergy elected to change its method of recognizing actuarial gains and losses for its defined benefit pension and OPEB plans. Previously, FirstEnergy recognized the net actuarial gains and losses as a component of AOCI and amortized the gains and losses into income over the remaining service life of affected employees within the related plans to the extent such


184


gains and losses were outside a corridor of the greater of 10% of the market-related value of plan assets or 10% of the plans' projected benefit obligation.

FirstEnergy has elected to immediately recognize the change in the fair value of plan assets and net actuarial gains and losses annually in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. The remaining components of pensions and OPEB expense, primarily service costs, interest on obligations, assumed return on assets and prior service costs, will be recorded on a quarterly basis.

While FirstEnergy's historical policy of recognizing pensions and OPEB expense was considered acceptable under GAAP, FirstEnergy believes that the new policy is preferable as it eliminates the delay in recognizing gains and losses to earnings. The change will also improve transparency to FirstEnergy's operational results and benefits plan performance by immediately recognizing deviations from expected actuarial assumptions in the year they are incurred.

This change in accounting policy has been applied retrospectively, adjusting all prior periods presented. Applying this change retrospectively increased property, plant and equipment as a result of capitalizing a portion of the pension and OPEB costs now recognized for each year in addition to additional depreciation expense. As a result of increasing those asset balances, FirstEnergy recognized additional affiliated company asset transfers associated with ATSI and the Generation Asset Transfer, and further impairments of certain long-lived assets in those periods. Additionally, the allocation of related pension and OPEB costs from FESC and AESC to FES and the Utility Registrants resulted in affiliated noncurrent liabilities as of December 31, 2011 of $331 million-FES, $80 million-OE, $56 million-CEI, $32 million-TE, $76 million-JCP&L, $40 million-Met-ED and $40 million-Penelec. The impact of this accounting policy change on the financial statements is summarized below:


185


FirstEnergy           
CONSOLIDATED STATEMENTS OF INCOMEYear Ended December 31, 2010 Year Ended December 31, 2009
(In millions, except per share amounts)As Effect of As As Effect of As
 Reported Change Revised Reported Change Revised
Other operating expense$2,850
 $(154) $2,696
 $2,697
 $(146) $2,551
Pensions and OPEB mark-to-market adjustment—
 190
 190
 —
 321
 321
Provision for depreciation746
 22
 768
 736
 21
 757
Impairment of long-lived assets384
 4
 388
 6
 —
 6
Capitalized interest165
 —
 165
 130
 1
 131
Income before income taxes1,242
 (62) 1,180
 1,235
 (195) 1,040
Income taxes482
 (20) 462
 245
 (61) 184
Net Income760
 (42) 718
 990
 (134) 856
Earnings available to FirstEnergy Corp.784
 (42) 742
 1,006
 (134) 872
Basic earnings per share of common stock$2.58
 $(0.14) $2.44
 $3.31
 $(0.44) $2.87
Diluted earnings per share of common stock$2.57
 $(0.15) $2.42
 $3.29
 $(0.44) $2.85
            
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOMEYear Ended December 31, 2010 Year Ended December 31, 2009
(In millions)As Effect of As As Effect of As
 Reported Change Revised Reported Change Revised
Net Income$760
 $(42) $718
 $990
 $(134) $856
Pension and other postretirement benefits(258) 38
 (220) 15
 260
 275
Income taxes (benefits) on other comprehensive income(90) 16
 (74) 27
 101
 128
Comprehensive income636
 (20) 616
 955
 25
 980
Comprehensive income attributable to FirstEnergy Corp.660
 (20) 640
 971
 25
 996
            
CONSOLIDATED BALANCE SHEETSAs of December 31, 2010      
(In millions)As Effect of As      
 Reported Change Revised      
Property, plant & equipment - In service$29,451
 $825
 $30,276
      
Accumulated provision for depreciation11,180
 103
 11,283
      
Total property, plant, and equipment18,271
 722
 18,993
      
Regulatory assets1,826
 4
 1,830
      
Total assets34,805
 726
 35,531
      
Accumulated other comprehensive income (loss)(1,539) 1,964
 425
      
Retained earnings4,609
 (1,525) 3,084
      
Total common stockholders' equity8,545
 439
 8,984
      
Total equity8,513
 439
 8,952
      
Total capitalization21,092
 439
 21,531
      
Accrued taxes326
 6
 332
      
Accumulated deferred income taxes2,879
 281
 3,160
      
Total liabilities and capitalization34,805
 726
 35,531
      
            
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITYYear Ended December 31, 2010 Year Ended December 31, 2009
(In millions)As Effect of As As Effect of As
 Reported Change Revised Reported Change Revised
Retained Earnings-           
Beginning Balance$4,495
 $(1,483) $3,012
 $4,159
 $(1,349) $2,810
Earnings available to Parent784
 (42) 742
 1,006
 (134) 872
Ending Balance4,609
 (1,525) 3,084
 4,495
 (1,483) 3,012
            
Accumulated Comprehensive Income (Loss)-           
Beginning Balance$(1,415) $1,942
 $527
 $(1,380) $1,783
 $403
Pension and other postretirement benefits, net of taxes(151) 22
 (129) (19) 159
 140
Ending Balance(1,539) 1,964
 425
 (1,415) 1,942
 527
            
CONSOLIDATED STATEMENTS OF CASH FLOWYear Ended December 31, 2010 Year Ended December 31, 2009
(In millions)As Effect of As As Effect of As
 Reported Change Revised Reported Change Revised
Cash flows provided by operating activities:           
Net income$760
 $(42) $718
 $990
 $(134) $856
Provision for depreciation746
 22
 768
 736
 21
 757
Deferred income taxes and investment tax credits, net470
 (20) 450
 384
 (61) 323
Pensions and OPEB mark-to-market adjustment—
 190
 190
 —
 321
 321
Accrued compensation and retirement benefits89
 (154) (65) 22
 (146) (124)
Impairments of long-lived assets384
 4
 388
 6
 —
 6
Other operating activities45
 —
 45
 30
 (1) 29


186


FES           
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOMEYear Ended December 31, 2010 Year Ended December 31, 2009
(In millions)As Effect of As As Effect of As
 Reported Change Revised Reported Change Revised
Other operating expense$1,280
 $(50) $1,230
 $1,183
 $(40) $1,143
Pensions and OPEB mark-to-market adjustment—
 107
 107
 —
 150
 150
Provision for depreciation243
 3
 246
 259
 3
 262
Impairment of long-lived assets384
 4
 388
 6
 —
 6
Income before income taxes420
 (64) 356
 892
 (113) 779
Income taxes151
 (26) 125
 315
 (34) 281
Net Income269
 (38) 231
 577
 (79) 498
Pension and other postretirement benefits(58) 28
 (30) 14
 54
 68
Income taxes (benefits) on other comprehensive income(11) 14
 3
 (6) 20
 14
Comprehensive income252
 (24) 228
 566
 (45) 521
            
CONSOLIDATED BALANCE SHEETSAs of December 31, 2010  
(In millions)As Effect of As      
 Reported Change Revised      
Property, plant & equipment - In service$11,321
 $106
 $11,427
      
Accumulated provision for depreciation4,024
 14
 4,038
      
Total property, plant, and equipment7,297
 92
 7,389
      
Total assets12,063
 92
 12,155
      
Common stock1,490
 77
 1,567
      
Accumulated other comprehensive income (loss)(120) 182
 62
      
Retained earnings2,418
 (428) 1,990
      
Total equity3,788
 (169) 3,619
      
Total capitalization6,969
 (169) 6,800
      
Accumulated deferred income taxes58
 9
 67
      
Other noncurrent liabilities244
 252
 496
      
Total liabilities and capitalization12,063
 92
 12,155
      
            
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITYYear Ended December 31, 2010 Year Ended December 31, 2009
(In millions)As Effect of As As Effect of As
 Reported Change Revised Reported Change Revised
Retained Earnings-           
Beginning Balance2,149
 (390) 1,759
 1,572
 (311) 1,261
Net income269
 (38) 231
 577
 (79) 498
Ending Balance2,418
 (428) 1,990
 2,149
 (390) 1,759
            
Accumulated Comprehensive Income (Loss)-           
Beginning Balance(103) 168
 65
 (92) 134
 42
Pension and other postretirement benefits, net of taxes(36) 14
 (22) 6
 34
 40
Ending Balance(120) 182
 62
 (103) 168
 65
            
Common Stock-           
Beginning Balance1,468
 77
 1,545
 1,464
 77
 1,541
Ending Balance1,490
 77
 1,567
 1,468
 77
 1,545
            
CONSOLIDATED STATEMENTS OF CASH FLOWYear Ended December 31, 2010 Year Ended December 31, 2009
(In millions)As Effect of As As Effect of As
 Reported Change Revised Reported Change Revised
Cash flows provided by operating activities:           
Net income$269
 $(38) $231
 $577
 $(79) $498
Provision for depreciation243
 3
 246
 259
 3
 262
Deferred income taxes and investment tax credits, net176
 (26) 150
 220
 (34) 186
Pensions and OPEB mark-to-market adjustment—
 107
 107
 —
 150
 150
Accrued compensation and retirement benefits25
 (50) (25) 6
 (40) (34)
Impairments of long-lived assets384
 4
 388
 6
 —
 6


187


OE           
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOMEYear Ended December 31, 2010 Year Ended December 31, 2009
(In millions)As Effect of As As Effect of As
 Reported Change Revised Reported Change Revised
Other operating expense$364
 $(22) $342
 $461
 $(22) $439
Pensions and OPEB mark-to-market adjustment—
 24
 24
 —
 26
 26
Provision for depreciation88
 3
 91
 89
 3
 92
Income before income taxes238
 (5) 233
 188
 (7) 181
Income taxes81
 (3) 78
 66
 (4) 62
Net Income157
 (2) 155
 122
 (3) 119
Pension and other postretirement benefits(27) (4) (31) 46
 7
 53
Income taxes (benefits) on other comprehensive income(11) 2
 (9) 16
 3
 19
Comprehensive income141
 (8) 133
 143
 1
 144
            
CONSOLIDATED BALANCE SHEETSAs of December 31, 2010      
(In millions)As Effect of As      
 Reported Change Revised      
Utility plant - In service$3,137
 $85
 $3,222
      
Accumulated provision for depreciation1,208
 10
 1,218
      
Total property, plant, and equipment1,929
 75
 2,004
      
Regulatory assets400
 3
 403
      
Total assets3,686
 78
 3,764
      
Common Stock952
 (39) 913
      
Accumulated other comprehensive income (loss)(179) 261
 82
      
Retained earnings142
 (254) (112)      
Total common stockholder's equity915
 (32) 883
      
Total equity921
 (32) 889
      
Total capitalization2,073
 (32) 2,041
      
Accrued taxes79
 1
 80
      
Accumulated deferred income taxes696
 41
 737
      
Other noncurrent liabilities197
 68
 265
      
Total liabilities and capitalization3,686
 78
 3,764
      
            
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITYYear Ended December 31, 2010 Year Ended December 31, 2009
(In millions)As Effect of As As Effect of As
 Reported Change Revised Reported Change Revised
Retained Earnings-           
Beginning Balance$30
 $(252) $(222) $254
 $(249) $5
Earnings available to Parent157
 (2) 155
 122
 (3) 119
Ending Balance142
 (254) (112) 30
 (252) (222)
            
Accumulated Comprehensive Income (Loss)-           
Beginning Balance$(163) $267
 $104
 $(184) $263
 $79
Pension and other postretirement benefits, net of taxes(16) (6) (22) 26
 4
 30
Ending Balance(179) 261
 82
 (163) 267
 104
            
Common Stock-           
Beginning Balance$1,155
 $(39) $1,116
 $1,224
 $(39) $1,185
Ending Balance952
 (39) 913
 1,155
 (39) 1,116
            
CONSOLIDATED STATEMENTS OF CASH FLOWYear Ended December 31, 2010 Year Ended December 31, 2009
(In millions)As Effect of As As Effect of As
 Reported Change Revised Reported Change Revised
Cash flows provided by operating activities:           
Net income$157
 $(2) $155
 $122
 $(3) $119
Provision for depreciation88
 3
 91
 89
 3
 92
Deferred income taxes and investment tax credits, net46
 (3) 43
 41
 (4) 37
Pensions and OPEB mark-to-market adjustment—
 24
 24
 —
 26
 26
Accrued compensation and retirement benefits(23) (22) (45) (14) (22) (36)


188


CEI           
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOMEYear Ended December 31, 2010 Year Ended December 31, 2009
(In thousands)As Effect of As As Effect of As
 Reported Change Revised Reported Change Revised
Other operating expense$130,018
 $(14,952) $115,066
 $161,407
 $(12,840) $148,567
Pensions and OPEB mark-to-market adjustment—
 11,945
 11,945
 —
 38,329
 38,329
Provision for depreciation72,753
 2,154
 74,907
 71,908
 1,975
 73,883
Capitalized interest82
 (19) 63
 173
 88
 261
Income before income taxes111,848
 834
 112,682
 (21,175) (27,376) (48,551)
Income taxes38,673
 (3,546) 35,127
 (10,183) (9,611) (19,794)
Net Income73,175
 4,380
 77,555
 (10,992) (17,765) (28,757)
Earnings available to Parent71,658
 4,380
 76,038
 (12,706) (17,765) (30,471)
Pension and other postretirement benefits(26,955) (13,487) (40,442) (1,378) 47,566
 46,188
Income taxes (benefits) on other comprehensive income(11,926) (2,806) (14,732) 1,923
 17,374
 19,297
Comprehensive income58,146
 (6,301) 51,845
 (14,293) 12,427
 (1,866)
Comprehensive income available to Parent56,629
 (6,301) 50,328
 (16,007) 12,427
 (3,580)
            
CONSOLIDATED BALANCE SHEETSAs of December 31, 2010      
(In thousands)As Effect of As      
 Reported Change Revised      
Utility plant - In service$2,396,893
 $63,224
 $2,460,117
      
Accumulated provision for depreciation932,246
 12,371
 944,617
      
Total property, plant, and equipment1,464,647
 50,853
 1,515,500
      
Regulatory assets370,403
 (574) 369,829
      
Total assets4,303,849
 50,279
 4,354,128
      
Common Stock887,087
 (23,715) 863,372
      
Accumulated other comprehensive income (loss)(153,187) 187,298
 34,111
      
Retained earnings568,906
 (187,230) 381,676
      
Total common stockholder's equity1,302,806
 (23,647) 1,279,159
      
Total equity1,320,823
 (23,647) 1,297,176
      
Total capitalization3,173,353
 (23,647) 3,149,706
      
Accrued taxes84,668
 678
 85,346
      
Accumulated deferred income taxes622,771
 24,521
 647,292
      
Other noncurrent liabilities100,161
 48,727
 148,888
      
Total liabilities and capitalization4,303,849
 50,279
 4,354,128
      
            
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITYYear Ended December 31, 2010 Year Ended December 31, 2009
(In thousands)As Effect of As As Effect of As
 Reported Change Revised Reported Change Revised
Retained Earnings-           
Beginning Balance$597,248
 $(191,610) $405,638
 $859,954
 $(173,845) $686,109
Earnings available to Parent71,658
 4,380
 76,038
 (12,706) (17,765) (30,471)
Ending Balance568,906
 (187,230) 381,676
 597,248
 (191,610) 405,638
            
Accumulated Comprehensive Income (Loss)-           
Beginning Balance$(138,158) $197,979
 $59,821
 $(134,857) $167,787
 $32,930
Pension and other postretirement benefits, net of taxes(15,029) (10,681) (25,710) (3,301) 30,192
 26,891
Ending Balance(153,187) 187,298
 34,111
 (138,158) 197,979
 59,821
            
Common Stock-           
Beginning Balance$884,897
 $(23,715) $861,182
 $878,785
 $(23,715) $855,070
Ending Balance887,087
 (23,715) 863,372
 884,897
 (23,715) 861,182
            
CONSOLIDATED STATEMENTS OF CASH FLOWYear Ended December 31, 2010 Year Ended December 31, 2009
(In thousands)As Effect of As As Effect of As
 Reported Change Revised Reported Change Revised
Cash flows provided by operating activities:           
Net income$73,175
 $4,380
 $77,555
 $(10,992) $(17,765) $(28,757)
Provision for depreciation72,753
 2,154
 74,907
 71,908
 1,975
 73,883
Deferred income taxes and investment tax credits, net(20,068) (3,546) (23,614) (51,839) (9,611) (61,450)
Pensions and OPEB mark-to-market adjustment—
 11,945
 11,945
 —
 38,329
 38,329
Accrued compensation and retirement benefits12,724
 (14,952) (2,228) 8,514
 (12,840) (4,326)
Other operating activities2,090
 19
 2,109
 8,820
 (88) 8,732


189


TE           
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOMEYear Ended December 31, 2010 Year Ended December 31, 2009
(In thousands)As Effect of As As Effect of As
 Reported Change Revised Reported Change Revised
Other operating expense$108,072
 $(6,177) $101,895
 $142,203
 $(6,265) $135,938
Pensions and OPEB mark-to-market adjustment—
 4,183
 4,183
 —
 14,360
 14,360
Provision for depreciation31,613
 548
 32,161
 30,727
 454
 31,181
Miscellaneous expense(4,206) (81) (4,287) (2,436) 267
 (2,169)
Capitalized interest358
 (54) 304
 169
 114
 283
Income before income taxes50,693
 1,311
 52,004
 31,917
 (8,168) 23,749
Income taxes17,645
 (1,889) 15,756
 7,939
 (2,592) 5,347
Net Income33,048
 3,200
 36,248
 23,978
 (5,576) 18,402
Earnings available to Parent33,044
 3,200
 36,244
 23,957
 (5,576) 18,381
Pension and other postretirement benefits(655) (6,295) (6,950) (7,880) 16,958
 9,078
Income taxes (benefits) on other comprehensive income(1,144) (277) (1,421) (6,630) 6,097
 (533)
Comprehensive income33,668
 (2,818) 30,850
 7,547
 5,285
 12,832
Comprehensive income available to Parent33,664
 (2,818) 30,846
 7,526
 5,285
 12,811
            
CONSOLIDATED BALANCE SHEETSAs of December 31, 2010      
(In thousands)As Effect of As      
 Reported Change Revised      
Utility plant - In service$947,203
 $15,225
 $962,428
      
Accumulated provision for depreciation446,401
 4,130
 450,531
      
Total property, plant, and equipment500,802
 11,095
 511,897
      
Regulatory assets72,059
 529
 72,588
      
Total assets1,614,306
 11,624
 1,625,930
      
Other Paid-In Capital178,182
 (15,161) 163,021
      
Accumulated other comprehensive income (loss)(49,183) 64,269
 15,086
      
Retained earnings117,534
 (75,034) 42,500
      
Total common stockholder's equity393,543
 (25,926) 367,617
      
Total equity396,132
 (25,926) 370,206
      
Total capitalization996,625
 (25,926) 970,699
      
Accrued taxes24,401
 222
 24,623
      
Accumulated deferred income taxes132,019
 8,696
 140,715
      
Other noncurrent liabilities65,090
 28,632
 93,722
      
Total liabilities and capitalization1,614,306
 11,624
 1,625,930
      
            
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITYYear Ended December 31, 2010 Year Ended December 31, 2009
(In thousands)As Effect of As As Effect of As
 Reported Change Revised Reported Change Revised
Retained Earnings-           
Beginning Balance$214,490
 $(78,234) $136,256
 $190,533
 $(72,658) $117,875
Earnings available to Parent33,044
 3,200
 36,244
 23,957
 (5,576) 18,381
Ending Balance117,534
 (75,034) 42,500
 214,490
 (78,234) 136,256
            
Accumulated Comprehensive Income (Loss)-           
Beginning Balance$(49,803) $70,287
 $20,484
 $(33,372) $59,426
 $26,054
Pension and other postretirement benefits, net of taxes535
 (6,018) (5,483) (7,006) 10,861
 3,855
Ending Balance(49,183) 64,269
 15,086
 (49,803) 70,287
 20,484
            
Other Paid-In Capital-           
Beginning Balance$178,181
 $(15,161) $163,020
 $175,879
 $(15,161) $160,718
Ending Balance178,182
 (15,161) 163,021
 178,181
 (15,161) 163,020
            
CONSOLIDATED STATEMENTS OF CASH FLOWYear Ended December 31, 2010 Year Ended December 31, 2009
(In thousands)As Effect of As As Effect of As
 Reported Change Revised Reported Change Revised
Cash flows provided by operating activities:           
Net income$33,048
 $3,200
 $36,248
 $23,978
 $(5,576) $18,402
Provision for depreciation31,613
 548
 32,161
 30,727
 454
 31,181
Deferred income taxes and investment tax credits, net28,041
 (1,889) 26,152
 2,003
 (2,592) (589)
Pensions and OPEB mark-to-market adjustment—
 4,183
 4,183
 —
 14,360
 14,360
Accrued compensation and retirement benefits5,517
 (6,177) (660) 3,489
 (6,265) (2,776)
Other operating activities(7,689) 135
 (7,554) 7,135
 (381) 6,754


190


JCP&L           
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOMEYear Ended December 31, 2010 Year Ended December 31, 2009
(In millions)As Effect of As As Effect of As
 Reported Change Revised Reported Change Revised
Other operating expense$344
 $(21) $323
 $310
 $(26) $284
Pensions and OPEB mark-to-market adjustment—
 26
 26
 —
 37
 37
Provision for depreciation108
 5
 113
 103
 5
 108
Income before income taxes340
 (10) 330
 279
 (16) 263
Income taxes148
 (1) 147
 109
 (4) 105
Net Income192
 (9) 183
 170
 (12) 158
Pension and other postretirement benefits(19) 2
 (17) (40) 22
 (18)
Income taxes (benefits) on other comprehensive income(9) (1) (10) (14) 10
 (4)
Comprehensive income182
 (6) 176
 144
 —
 144
            
CONSOLIDATED BALANCE SHEETSAs of December 31, 2010      
(In millions)As Effect of As      
 Reported Change Revised      
Utility plant - In service$4,563
 $220
 $4,783
      
Accumulated provision for depreciation1,657
 25
 1,682
      
Total property, plant, and equipment2,906
 195
 3,101
      
Regulatory assets513
 1
 514
      
Total assets6,317
 196
 6,513
      
Accumulated other comprehensive income (loss)(253) 304
 51
      
Retained earnings227
 (250) (23)      
Total common stockholder's equity2,619
 54
 2,673
      
Total capitalization4,389
 54
 4,443
      
Other26
 2
 28
      
Accumulated deferred income taxes716
 77
 793
      
Other noncurrent liabilities171
 63
 234
      
Total liabilities and capitalization6,317
 196
 6,513
      
            
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITYYear Ended December 31, 2010 Year Ended December 31, 2009
(In millions)As Effect of As As Effect of As
 Reported Change Revised Reported Change Revised
Retained Earnings-           
Beginning Balance$200
 $(241) $(41) $157
 $(229) $(72)
Net Income192
 (9) 183
 170
 (12) 158
Ending Balance227
 (250) (23) 200
 (241) (41)
            
Accumulated Comprehensive Income (Loss)-           
Beginning Balance$(243) $301
 $58
 $(217) $289
 $72
Pension and other postretirement benefits, net of taxes(10) 3
 (7) (26) 12
 (14)
Ending Balance(253) 304
 51
 (243) 301
 58
            
CONSOLIDATED STATEMENTS OF CASH FLOWYear Ended December 31, 2010 Year Ended December 31, 2009
(In millions)As Effect of As As Effect of As
 Reported Change Revised Reported Change Revised
Cash flows provided by operating activities:           
Net income$192
 $(9) $183
 $170
 $(12) $158
Provision for depreciation108
 5
 113
 103
 5
 108
Deferred income taxes and investment tax credits, net32
 (1) 31
 43
 (4) 39
Pensions and OPEB mark-to-market adjustment—
 26
 26
 —
 37
 37
Accrued compensation and retirement benefits14
 (21) (7) 13
 (26) (13)


191


Met-Ed           
CONSOLIDATED STATEMENTS OF INCOMEYear Ended December 31, 2010 Year Ended December 31, 2009
(In thousands)As Effect of As As Effect of As
 Reported Change Revised Reported Change Revised
Other operating expense$418,569
 $(17,553) $401,016
 $277,024
 $(17,889) $259,135
Pensions and OPEB mark-to-market adjustment—
 6,993
 6,993
 —
 16,044
 16,044
Provision for depreciation52,176
 3,616
 55,792
 51,006
 3,646
 54,652
Miscellaneous income5,901
 —
 5,901
 4,033
 74
 4,107
Capitalized interest653
 —
 653
 159
 22
 181
Income before income taxes100,873
 6,944
 107,817
 84,117
 (1,705) 82,412
Income taxes42,866
 4,867
 47,733
 28,594
 281
 28,875
Net Income58,007
 2,077
 60,084
 55,523
 (1,986) 53,537
Pension and other postretirement benefits289
 (13,257) (12,968) (118) 685
 567
Income taxes (benefits) on other comprehensive income(544) (7,008) (7,552) 2,784
 286
 3,070
Comprehensive income59,175
 (4,172) 55,003
 52,956
 (1,587) 51,369
            
CONSOLIDATED BALANCE SHEETSAs of December 31, 2010      
(In thousands)As Effect of As      
 Reported Change Revised      
Utility plant - In service$2,247,853
 $145,648
 $2,393,501
      
Accumulated provision for depreciation846,003
 16,514
 862,517
      
Total property, plant, and equipment1,401,850
 129,134
 1,530,984
      
Regulatory assets295,856
 52
 295,908
      
Total assets3,044,670
 129,186
 3,173,856
      
Accumulated other comprehensive income (loss)(142,383) 179,807
 37,424
      
Retained earnings32,406
 (138,967) (106,561)      
Total common stockholder's equity1,087,099
 40,840
 1,127,939
      
Total capitalization1,805,959
 40,840
 1,846,799
      
Accrued taxes60,856
 482
 61,338
      
Accumulated deferred income taxes473,009
 53,458
 526,467
      
Other noncurrent liabilities53,689
 34,406
 88,095
      
Total liabilities and capitalization3,044,670
 129,186
 3,173,856
      
            
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITYYear Ended December 31, 2010 Year Ended December 31, 2009
(In thousands)As Effect of As As Effect of As
 Reported Change Revised Reported Change Revised
Retained Earnings-           
Beginning Balance$4,399
 $(141,044) $(136,645) $(51,124) $(139,058) $(190,182)
Net income58,007
 2,077
 60,084
 55,523
 (1,986) 53,537
Ending Balance32,406
 (138,967) (106,561) 4,399
 (141,044) (136,645)
            
Accumulated Comprehensive Income (Loss)-           
Beginning Balance$(143,551) $186,056
 $42,505
 $(140,984) $185,657
 $44,673
Pension and other postretirement benefits, net of taxes1,355
 (6,249) (4,894) (2,902) 399
 (2,503)
Ending Balance(142,383) 179,807
 37,424
 (143,551) 186,056
 42,505
            
CONSOLIDATED STATEMENTS OF CASH FLOWYear Ended December 31, 2010 Year Ended December 31, 2009
(In thousands)As Effect of As As Effect of As
 Reported Change Revised Reported Change Revised
Cash flows provided by operating activities:           
Net income$58,007
 $2,077
 $60,084
 $55,523
 $(1,986) $53,537
Provision for depreciation52,176
 3,616
 55,792
 51,006
 3,646
 54,652
Deferred income taxes and investment tax credits, net29,528
 4,867
 34,395
 66,965
 281
 67,246
Pensions and OPEB mark-to-market adjustment—
 6,993
 6,993
 —
 16,044
 16,044
Accrued compensation and retirement benefits(2,474) (17,553) (20,027) 5,876
 (17,889) (12,013)
Other operating activities8,026
 —
 8,026
 5,022
 (96) 4,926


192


Penelec           
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOMEYear Ended December 31, 2010 Year Ended December 31, 2009
(In thousands)As Effect of As As Effect of As
 Reported Change Revised Reported Change Revised
Other operating expense$268,614
 $(21,648) $246,966
 $209,156
 $(16,395) $192,761
Pensions and OPEB mark-to-market adjustment—
 8,279
 8,279
 —
 33,983
 33,983
Provision for depreciation61,141
 4,553
 65,694
 61,317
 4,320
 65,637
Miscellaneous income5,928
 29
 5,957
 3,662
 —
 3,662
Capitalized interest750
 20
 770
 98
 132
 230
Income before income taxes100,665
 8,865
 109,530
 111,082
 (21,776) 89,306
Income taxes41,173
 5,167
 46,340
 45,694
 (7,186) 38,508
Net Income59,492
 3,698
 63,190
 65,388
 (14,590) 50,798
Pension and other postretirement benefits(5,749) (14,672) (20,421) (51,421) 50,601
 (820)
Income taxes (benefits) on other comprehensive income(4,262) (7,532) (11,794) (17,252) 22,083
 4,831
Comprehensive income58,070
 (3,442) 54,628
 31,281
 13,928
 45,209
            
CONSOLIDATED BALANCE SHEETSAs of December 31, 2010      
(In thousands)As Effect of As      
 Reported Change Revised      
Utility plant - In service$2,532,629
 $181,912
 $2,714,541
      
Accumulated provision for depreciation935,259
 20,055
 955,314
      
Total property, plant, and equipment1,597,370
 161,857
 1,759,227
      
Regulatory assets163,407
 21
 163,428
      
Total assets3,062,669
 161,878
 3,224,547
      
Accumulated other comprehensive income (loss)(163,526) 213,908
 50,382
      
Retained earnings60,993
 (151,872) (90,879)      
Total common stockholder's equity899,538
 62,036
 961,574
      
Total capitalization1,971,800
 62,036
 2,033,836
      
Accrued taxes5,075
 1,456
 6,531
      
Accumulated deferred income taxes371,877
 65,655
 437,532
      
Other noncurrent liabilities47,889
 32,731
 80,620
      
Total liabilities and capitalization3,062,669
 161,878
 3,224,547
      
            
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITYYear Ended December 31, 2010 Year Ended December 31, 2009
(In thousands)As Effect of As As Effect of As
 Reported Change Revised Reported Change Revised
Retained Earnings-           
Beginning Balance$91,501
 $(155,570) $(64,069) $76,113
 $(140,980) $(64,867)
Net Income59,492
 3,698
 63,190
 65,388
 (14,590) 50,798
Ending Balance60,993
 (151,872) (90,879) 91,501
 (155,570) (64,069)
            
Accumulated Comprehensive Income (Loss)-           
Beginning Balance$(162,104) $221,048
 $58,944
 $(127,997) $192,530
 $64,533
Pension and other postretirement benefits, net of taxes(1,382) (7,140) (8,522) (34,177) 28,518
 (5,659)
Ending Balance(163,526) 213,908
 50,382
 (162,104) 221,048
 58,944
            
CONSOLIDATED STATEMENTS OF CASH FLOWYear Ended December 31, 2010 Year Ended December 31, 2009
(In thousands)As Effect of As As Effect of As
 Reported Change Revised Reported Change Revised
Cash flows provided by operating activities:           
Net income$59,492
 $3,698
 $63,190
 $65,388
 $(14,590) $50,798
Provision for depreciation61,141
 4,553
 65,694
 61,317
 4,320
 65,637
Deferred income taxes and investment tax credits, net133,885
 5,167
 139,052
 63,065
 (7,186) 55,879
Pensions and OPEB mark-to-market adjustment—
 8,279
 8,279
 —
 33,983
 33,983
Accrued compensation and retirement benefits8,206
 (21,648) (13,442) 3,866
 (16,395) (12,529)
Other operating activities4,909
 (49) 4,860
 3,236
 (132) 3,104
2. MERGER
Purchase Price Allocation
On February 25, 2011, the merger between FE and AE closed. Pursuant to the terms of the Agreement and Plan of Merger among FE, Merger Sub and AE, Merger Sub merged with and into AE, with AE continuing as the surviving corporation and becoming a wholly owned subsidiary of FE. As part of the merger, AE shareholders received 0.667 of a share of FE common stock for each share of AE common stock outstanding as of the date the merger was completed, and all outstanding AE equity-based employee compensation awards were converted into FE equity-based awards on the same basis.


193


The total consideration in the merger was based on the closing price of a share of FE common stock on February 24, 2011, the day prior to the date the merger was completed, and was calculated as follows (in millions, except per share data):
Shares of AE common stock outstanding on February 24, 2011170
Exchange ratio0.667
Number of shares of FirstEnergy common stock issued113
Closing price of FirstEnergy common stock on February 24, 2011$38.16
Fair value of shares issued by FirstEnergy$4,327
Fair value of replacement share-based compensation awards relating to pre-merger service27
Total consideration transferred$4,354

The allocation of the total consideration transferred in the merger to the assets acquired and liabilities assumed includes adjustments for the fair value of Allegheny coal contracts, energy supply contracts, emission allowances, unregulated property, plant and equipment, derivative instruments, goodwill, intangible assets, long-term debt and accumulated deferred income taxes. The allocation of the purchase price was as follows:
  FE  FES  OE  CEI  TE  JCP&L  Met-Ed  Penelec 
2009 (In millions) 
Pension and other postretirement benefits $(78) $(3) $(5) $(11) $(2) $(18) $(11) $(5)
Gain on investments  157   139   10   -   7   -   -   - 
Loss on derivative hedges  (67)  (27)  -   -   -   -   -   - 
   12   109   5   (11)  5   (18)  (11)  (5)
Income taxes (benefits) related to reclassification to net income  4   41   2   (4)  2   (8)  (5)  (2)
Reclassification to net income $8  $68  $3  $(7) $3  $(10) $(6) $(3)
                                 
2008                                
Pension and other postretirement benefits $80  $7  $16  $1  $-  $14  $9  $14 
Gain on investments  40   31   9   -   1   -   -   - 
Loss on derivative hedges  (19)  (3)  -   -   -   -   -   - 
   101   35   25   1   1   14   9   14 
Income taxes related to reclassification to net income  41   14   10   -   -   6   4   6 
Reclassification to net income $60  $21   15   1   1   8   5   8 
                                 
2007                                
Pension and other postretirement benefits $45  $5  $14  $(5) $(2) $8  $6  $11 
Gain on investments  10   10   -   -   -   -   -   - 
Loss on derivative hedges  (26)  (12)  -   -   -   -   -   - 
   29   3   14   (5)  (2)  8   6   11 
Income taxes (benefits) related to  reclassification to net income  14   1   6   (2)  (1)  4   3   5 
Reclassification to net income $15  $2  $8  $(3) $(1) $4  $3  $6 
(In millions) 
  
Current assets$1,493
Property, plant and equipment9,660
Investments138
Goodwill866
Other noncurrent assets1,353
Current liabilities(718)
Noncurrent liabilities(3,444)
Long-term debt and other long-term obligations(4,994)
 $4,354

The allocation of purchase price in the table above reflects refinements made since the merger date in the determination of the fair values of income tax benefits, certain coal contracts and an adverse purchase power contract. This primarily resulted in an increase to property, plant and equipment, other noncurrent assets and current liabilities of approximately $4 million, $91 million and $4 million, respectively, and decreases to current assets, goodwill and noncurrent liabilities of $16 million, $86 million and $9 million, respectively. The impact of the refinements on the amortization of purchase accounting adjustments recorded during 2011 was not significant.
The estimated fair values of the assets acquired and liabilities assumed have been determined based on the accounting guidance for fair value measurements under GAAP, which defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.
The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. The Allegheny delivery, transmission and unregulated generation businesses have been assigned to the Regulated Distribution, Regulated Independent Transmission and Competitive Energy Services segments, respectively. The goodwill from the merger of $866 million has been assigned to the Competitive Energy Services segment based on expected synergies from the merger. The goodwill is not deductible for tax purposes.



194


The valuation of the additional intangible assets and liabilities recorded as result of the merger is as follows:
(In millions) Preliminary Valuation Weighted Average Amortization Period
Above market contracts:    
Energy contracts $189
 10 years
NUG contracts 124
 25 years
Coal supply contracts 516
 8 years
  829
  
Below market contracts:    
NUG contracts 143
 13 years
Coal supply contracts 83
 7 years
Transportation contract 35
 8 years
  261
  
Net intangible assets $568
  

The fair value measurements of intangible assets and liabilities were based on significant unobservable inputs and thus represent level 3 measurements as defined in accounting guidance for fair value measurements.
The fair value of Allegheny’s energy, NUG and gas transportation contracts, both above-market and below-market, were estimated based on the present value of the above/below market cash flows attributable to the contracts based on the contract type, discounted by a current market interest rate consistent with the overall credit quality of the contract portfolio. The above/below market cash flows were estimated by comparing the expected cash flow based on existing contracted prices and expected volumes with the cash flows from estimated current market contract prices for the same expected volumes. The estimated current market contract prices were derived considering current market prices, such as the price of energy and transmission, miscellaneous fees and a normal profit margin. The weighted average amortization period was determined based on the expected volumes to be delivered over the life of the contract.
The fair value of coal supply contracts was determined in a similar manner as the energy, NUG and gas transportation contracts, based on the present value of the above/below market cash flows attributable to the contracts. The fair value adjustments for these contracts are being amortized based on expected deliveries under each contract. See Note 7, Intangible Assets for additional information related to Intangible assets.
Acquired land easements and software with a fair value of $190 million are included in “Property, plant and equipment” on FirstEnergy’s Consolidated Balance Sheet as of December 31, 2011.
In connection with the merger, FirstEnergy recorded merger transaction costs, which included change in control and other benefit payments to AE executives, of approximately $91 million ($73 million net of tax) and $65 million ($47 million net of tax) during 2011 and 2010, respectively. These costs are included in “Other operating expenses” in the Consolidated Statements of Income.
FirstEnergy also recorded approximately $93 million ($91 million net of tax) in merger integration costs during 2011, including an inventory valuation adjustment. In connection with the merger, FirstEnergy reviewed its inventory levels as a result of combining the inventory of both companies. Following this review, FirstEnergy management determined that the combined inventory stock contained excess and duplicative items. FirstEnergy management also adopted a consistent excess and obsolete inventory practice for the combined entity. Application of the revised practice, in conjunction with those items identified as excess and duplicative, resulted in an inventory valuation adjustment of $67 million ($42 million net of tax) in the first quarter of 2011.
Revenues and earnings of Allegheny included in FirstEnergy’s Consolidated Statement of Income for the period beginning on the February 25, 2011, merger date are as follows:
  February 25 -
(In millions, except per share amounts) December 31, 2011
Total revenues $3,966
Earnings Available to FirstEnergy Corp.(1)
 $147
   
Basic Earnings Per Share $0.37
Diluted Earnings Per Share $0.37
(1)
Includes Allegheny’s after-tax merger costs of $58 million.


195


Pro Forma Financial Information
The following unaudited pro forma financial information reflects the consolidated results of operations of FirstEnergy as if the merger with AE had taken place on January 1, 2010. The unaudited pro forma information was calculated after applying FirstEnergy’s accounting policies and adjusting Allegheny’s results to reflect the depreciation and amortization that would have been charged assuming fair value adjustments to property, plant and equipment, debt and intangible assets had been applied on January 1, 2010, together with the consequential tax effects.
FirstEnergy and Allegheny both incurred merger-related costs that have been included in the pro forma earnings presented below. Combined pre-tax transaction costs incurred were approximately $91 million and $105 million in the years ended 2011 and 2010, respectively. In addition, during 2011, $93 million of pre-tax merger integration costs and $36 million of pre-tax charges from merger settlements approved by regulatory agencies were recognized.
The unaudited pro forma financial information has been presented below for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the merger been completed on January 1, 2010, or the future consolidated results of operations of the combined company.
(Pro forma amounts in millions, except per share amounts) 2011 2010
Revenues $17,449
 $18,569
Earnings available to FirstEnergy $979
 $1,183
     
Basic Earnings Per Share $2.34
 $2.83
Diluted Earnings Per Share $2.33
 $2.82
3. PENSIONPENSIONS AND OTHER POSTRETIREMENT BENEFIT PLANSPOSTEMPLOYMENT BENEFITS

As described in Note 1, Organization, Basis of Presentation and Significant Accounting Policies, FirstEnergy elected to change its method of recognizing actuarial gains and losses for its defined benefit pension plans and OPEB plans and applied this change retrospectively to all periods presented.
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 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. On September 2, 2009, the Utilities and ATSI made a combined $500 million voluntary contribution to their qualified pension plan. Due to the significance of the voluntary contribution, FirstEnergy elected to remeasure its qualified pension plan as of August 31, 2009. FirstEnergy estimates that additional cash contributions will not be required by law before 2012.

In addition, FirstEnergy 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 also available upon retirement to certain employees, hired prior to January 1, 2005, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing other postretirement benefitsOPEB to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. During 2006, FirstEnergy amended the OPEB plan effective in 2008 to cap the monthly contribution for many of the retirees and their spouses receiving subsidized health care coverage. During 2008, FirstEnergy further amended the OPEB plan effective in 2010 to limit the monthly contribution for pre-1990 retirees. On June 2, 2009, FirstEnergy amended its health care benefits plan for all employees and retirees eligible to participate in that plan. The 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. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.

FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. During 2011, FirstEnergy made pre-tax contributions to its qualified pension plans of $372 million. FirstEnergy made an additional $600 million pre-tax contribution to its qualified pension plan on January 5, 2012. Pension and OPEB costs are affected by employee demographics (including age, compensation levels and employment periods), the level of contributions made to the plans and earnings on plan assets. Pension and OPEB costs may also be affected by changes in key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. FirstEnergy uses a December 31 measurement date for its pension and OPEB plans. The fair value of the plan assets represents the actual market value as of the measurement date.

192

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

Obligations and Funded Status Pension Benefits  Other Benefits 
As of December 31
 2009  2008  2009  2008 
  (In millions) 
Change in benefit obligation            
Benefit obligation as of January 1
 $4,700  $4,750  $1,189  $1,182 
Service cost
  91   87   12   19 
Interest cost
  317   299   64   74 
Plan participants’ contributions
  -   -   29   25 
Plan amendments
  6   6   (408)  (20)
Special termination benefits
  -   -   13   - 
Medicare retiree drug subsidy
  -   -   20   2 
Actuarial (gain) loss
  648   (152)  23   12 
Benefits paid
  (370)  (290)  (119)  (105)
Benefit obligation as of December 31
 $5,392  $4,700  $823  $1,189 
                 
Change in fair value of plan assets
                
Fair value of plan assets as of January 1
 $3,752  $5,285  $440  $618 
Actual return on plan assets
  508   (1,251)  62   (152)
Company contributions
  509   8   55   54 
Plan participants’ contributions
  -   -   29   25 
Benefits paid
  (370)  (290)  (119)  (105)
Fair value of plan assets as of December 31
 $4,399  $3,752  $467  $440 
                 
Funded Status
                
Qualified plan
 $(787) $(774)        
Non-qualified plans
  (206)  (174)        
Funded status
 $(993) $(948) $(356) $(749)
                 
Accumulated benefit obligation
 $5,036  $4,367         
                 
Amounts Recognized on the Balance Sheet
                
Current liabilities
 $(10) $(8) $-  $- 
Noncurrent liabilities
  (983)  (940)  (356)  (749)
Net liability as of December 31
 $(993) $(948) $(356) $(749)
                 
Amounts Recognized in
                
Accumulated Other Comprehensive Income
                
Prior service cost (credit)
 $67  $80  $(1,145) $(912)
Actuarial loss
  2,486   2,182   756   801 
Net amount recognized
 $2,553  $2,262  $(389) $(111)
                 
Assumptions Used to Determine Benefit
                
Obligations as of December 31
                
Discount rate
  6.00%  7.00%  5.75%  7.00%
Rate of compensation increase
  5.20%  5.20%        
                 
Allocation of Plan Assets
                
As of December 31
                
Equity securities
  39%  47%  51%  56%
Bonds
  49   38   46   38 
Real estate
  6   9   1   2 
Private equities
  5   3   1   1 
Cash
  1   3   1   3 
Total
  100%  100%  100%  100%

193

Estimated 2010 Amortization of      
Net Periodic Pension Cost from Pension  Other 
Accumulated Other Comprehensive Income Benefits  Benefits 
  (In millions) 
Prior service cost (credit) $13  $(193)
Actuarial loss $188  $60 
  Pension Benefits  Other Benefits 
Components of Net Periodic Benefit Costs 2009  2008  2007  2009  2008  2007 
  (In millions) 
Service cost $91  $87  $88  $12  $19  $21 
Interest cost  317   299   294   64   74   69 
Expected return on plan assets  (343)  (463)  (449)  (36)  (51)  (50)
Amortization of prior service cost  13   13   13   (175)  (149)  (149)
Amortization of  net actuarial loss  179   8   45   61   47   45 
Net periodic cost $257  $(56) $(9) $(74) $(60) $(64)
FES’ and the Utilities’ shares of the netassumed Allegheny's pension and OPEB asset (liability)plans. FirstEnergy measured the funded status of the Allegheny pension plans and OPEB plans as of December 31, 2009the merger closing date using discount rates of 5.50% and 2008 are as follows:
  Pension Benefits  Other Benefits 
Net Pension and OPEB Asset (Liability)
 2009  2008  2009  2008 
  (In millions) 
FES
 $(361) $(193) $(19) $(124)
OE
  30   (38)  (74)  (167)
CEI
  (13)  (27)  (59)  (93)
TE
  (15)  (12)  (47)  (59)
JCP&L
  (77)  (128)  (56)  (58)
Met-Ed
  6   (89)  (28)  (52)
Penelec
  (79)  (64)  (84)  (103)

FES’ and the Utilities’ shares5.25%, respectively. The fair values of the net periodicplan assets for Allegheny’s pension and OPEB plans as of the date of the merger were $954 million and $75 million, respectively, and the actuarially determined benefit obligations for such plans as of that date were $1,341 million and $272 million, respectively. The expected returns on plan assets used to calculate net periodic costs for periods in 2011 subsequent to the three years ended December 31, 2009 are as follows:date of the merger were 8.25% for Allegheny’s qualified pension plan and 5.00% for Allegheny’s OPEB plans.


196


  Pension Benefits  Other Benefits 
Net Periodic Pension and OPEB Costs 2009  2008  2007  2009  2008  2007 
  (In millions) 
FES
 $71  $15  $21  $(15) $(7) $(10)
OE
  23   (26)  (16)  (14)  (7)  (11)
CEI
  17   (5)  1   -   2   4 
TE
  6   (3)  -   2   4   5 
JCP&L
  31   (15)  (9)  (6)  (16)  (16)
Met-Ed
  18   (10)  (7)  (4)  (10)  (10)
Penelec
  16   (13)  (10)  (4)  (13)  (13)
Assumptions Used                  
to Determine Net Periodic Benefit Cost 
Pension Benefits
  
Other Benefits
 
for Years Ended December 31 2009  2008  2007  2009  2008  2007 
Weighted-average discount rate  7.00%  6.50%  6.00%  7.00%  6.50%  6.00%
Expected long-term return on plan assets  9.00%  9.00%  9.00%  9.00%  9.00%  9.00%
Rate of compensation increase  5.20%  5.20%  3.50%            
Obligations and Funded Status Pensions OPEB
  2011 2010 2011 2010
  (In millions)
Change in benefit obligation:        
Benefit obligation as of January 1, $5,858
 $5,392
 $861
 $823
Liabilities assumed with Allegheny Merger 1,341
 —
 272
 —
Service cost 130
 99
 13
 10
Interest cost 374
 314
 48
 45
Plan participants’ contributions —
 —
 39
 30
Plan amendments —
 16
 (98) —
Special termination benefits 6
 —
 —
 —
Medicare retiree drug subsidy —
 —
 9
 7
Actuarial (gain) loss 647
 343
 19
 56
Benefits paid (379) (306) (126) (110)
Benefit obligation as of December 31, $7,977
 $5,858
 $1,037
 $861
         
Change in fair value of plan assets:        
Fair value of plan assets as of January 1, $4,544
 $4,399
 $498
 $467
Assets assumed with Allegheny Merger 954
 —
 75
 —
Actual return on plan assets 364
 440
 23
 52
Company contributions 384
 11
 19
 59
Plan participants’ contributions —
 —
 39
 30
Benefits paid (379) (306) (126) (110)
Fair value of plan assets as of December 31, $5,867
 $4,544
 $528
 $498
         
Funded Status:        
Qualified plan $(1,820) $(1,076)    
Non-qualified plans (290) (238)    
Funded Status $(2,110) $(1,314) $(509) $(363)
         
Accumulated benefit obligation $7,409
 $5,469
 $—
 $—
         
Amounts Recognized on the Balance Sheet:        
Current liabilities $(13) $(11) $—
 $—
Noncurrent liabilities (2,097) (1,303) (509) (363)
Net liability as of December 31, $(2,110) $(1,314) $(509) $(363)
         
Amounts Recognized in AOCI:        
Prior service cost (credit) $67
 $76
 $(847) $(952)
         
Assumptions Used to Determine Benefit Obligations        
(as of December 31)        
Discount rate 5.00% 5.50% 4.75% 5.00%
Rate of compensation increase 5.20% 5.20% 5.20% 5.20%
         
Allocation of Plan Assets (as of December 31)        
Equity securities 19% 28% 38% 47%
Bonds 48
 50
 44
 45
Absolute return strategies 21
 11
 13
 3
Real estate 6
 6
 1
 2
Private equities 2
 4
 —
 1
Cash 4
 1
 4
 2
Total 100% 100% 100% 100%

Accounting guidance establishes aThe estimated 2012 amortization of pensions and OPEB prior service costs (credits) from AOCI into net periodic pensions and OPEB costs is approximately $12 million and $(203) million, respectively.



197


  Pensions OPEB
Components of Net Periodic Benefit Costs 2011 2010 2009 2011 2010 2009
  (In millions)
Service cost $130
 $99
 $91
 $13
 $10
 $12
Interest cost 374
 314
 317
 48
 45
 64
Expected return on plan assets (446) (361) (343) (40) (36) (36)
Amortization of prior service cost (credit) 14
 13
 13
 (203) (193) (175)
Other adjustments (settlements, curtailments, etc.) 6
 —
 —
 —
 —
 —
Pensions & OPEB mark-to-market adjustment 729
 264
 483
 36
 22
 16
Net periodic cost $807
 $329
 $561
 $(146) $(152) $(119)
Assumptions Used to Determine Net Periodic Benefit Cost
for Years Ended December 31
 Pensions OPEB
 2011 2010 2009 2011 2010 2009
Weighted-average discount rate 5.50% 6.00% 7.00% 5.00% 5.75% 7.00%
Expected long-term return on plan assets 8.25% 8.50% 9.00% 8.50% 8.50% 9.00%
Rate of compensation increase 5.20% 5.20% 5.20% 5.20% 5.20% 5.20%
The following tables set forth pension financial assets and liabilities that are accounted for at fair value hierarchy that prioritizesby level within the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active marketsvalue hierarchy. See Note 9, Fair Value Measurements, for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levelsa description of each level of the fair value hierarchy defined by accounting guidance are as follows:hierarchy. There were no significant transfers between levels during 2011 and 2010.
  December 31, 2011 Asset Allocation
  Level 1 Level 2 Level 3 Total 
  (In millions)  
Cash and short-term securities $—
 $198
 $—
 $198
 4%
Equity investments          
Domestic 223
 323
 —
 546
 9%
International 198
 379
 —
 577
 10%
Fixed income          
Government bonds 348
 430
 —
 778
 13%
Corporate bonds —
 1,998
 —
 1,998
 34%
Distressed debt —
 —
 —
 —
 —%
Mortgaged-backed securities (non-government) —
 48
 —
 48
 1%
Alternatives          
Hedge funds —
 1,131
 —
 1,131
 19%
Derivatives —
 75
 70
 145
 2%
Private equity funds —
 —
 135
 135
 2%
Real estate funds —
 —
 327
 327
 6%
  $769
 $4,582
 $532
 $5,883
 100%


Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those where transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 assets include registered investment companies, common stocks, publicly traded real estate investment trusts and certain shorter duration, more liquid fixed income securities. Registered investment companies and common stocks are stated at fair value as quoted on a recognized securities exchange and are valued at the last reported sales price on the last business day of the plan year.  Real estate investment trusts’ and certain fixed income securities’ market values are based on daily quotes available on public exchanges as with other publicly traded equity and fixed income securities.198


194
  December 31, 2010 Asset Allocation
  Level 1 Level 2 Level 3 Total 
  (In millions)  
Cash and short-term securities $—
 $72
 $—
 $72
 1%
Equity investments          
Domestic 342
 189
 —
 531
 12%
International 118
 615
 —
 733
 16%
Fixed income          
Government bonds —
 722
 —
 722
 16%
Corporate bonds —
 1,414
 —
 1,414
 31%
Distressed debt —
 97
 —
 97
 2%
Mortgaged-backed securities (non-government) —
 52
 —
 52
 1%
Alternatives          
Hedge funds —
 497
 —
 497
 11%
Private equity funds —
 —
 119
 119
 4%
Real estate funds 2
 —
 282
 284
 6%
  $462
 $3,658
 $401
 $4,521
 100%

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. Additionally, Level 2 includes those financial instruments that are valued using models or other valuation methodologies based on assumptions that are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 2 investments include common collective trusts, certain real estate investment trusts, and fixed income assets. Common collective trusts are not available in an exchange and active market, however, the fair value is determined based on the underlying investments as traded in an exchange and active market.

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 in addition to the use of independent appraisers’ estimates of fair value on a periodic basis typically determined quarterly, but no less than annually. Assets in this category include private equity, limited partnership, certain real estate trusts and fixed income securities.   The fixed income securities’ market values are based in part on quantitative models and on observing market value ascertained through timely trades for securities’ that are similar in nature to the ones being valued.

As of December 31, 2009, the pension investments measured at fair value were as follows:

  December 31, 2009  Asset 
  Level 1  Level 2  Level 3  Total  Allocation 
Assets (in millions)    
Short-term securities $-  $337  $-  $337   7%
Common and preferred stocks  578   994   -   1,572   36%
Mutual funds  159   -   -   159   4%
Bonds  -   1,928   -   1,928   44%
Real estate/other assets  1   4   378   383   9%
  $738  $3,263  $378  $4,379   100%

The following table provides a reconciliation of changes in the fair value of pension investments classified as Level 3 in the fair value hierarchy during 2009:2011 and 2010:
  Private Equity Funds Real Estate Funds Derivatives
  (In millions)
Balance as of January 1, 2010 $137
 $241
 —
Actual return on plan assets:      
Unrealized gains (losses) 1
 45
 —
Realized gains (losses) 11
 (3) —
Purchases, sales and settlements (28) (1) —
Transfers in (out) (2) —
 —
Balance as of December 31, 2010 119
 282
 —
Actual return on plan assets:      
Unrealized gains 11
 28
 7
Realized gains (losses) 5
 17
 —
Purchases, sales and settlements —
 —
 63
Transfers in (out) —
 —
 —
Balance as of December 31, 2011 $135
 $327
 $70


  Real estate / Other assets 
  (in millions) 
Beginning balance $416 
Transfers  44 
Acquisitions/(Dispositions)  16 
Loss  (98)
Ending balance $378 
199


As of December 31, 2009,2011 and 2010, the other postretirement benefitOPEB trust investments measured at fair value were as follows:
  December 31, 2011 Asset Allocation
  Level 1 Level 2 Level 3 Total 
  (In millions)  
Cash and short-term securities $—
 $19
 $—
 $19
 4%
Equity investment          
Domestic 164
 25
 —
 189
 35%
International 15
 3
 —
 18
 3%
Mutual funds 7
 2
 —
 9
 2%
Fixed income          
U.S. treasuries —
 30
 —
 30
 6%
Government bonds 8
 136
 —
 144
 27%
Corporate bonds —
 89
 —
 89
 17%
Distressed debt —
 —
 —
 —
 —%
Mortgage-backed securities (non-government) —
 5
 —
 5
 —%
Alternatives          
Hedge funds —
 25
 —
 25
 5%
Private equity funds —
 —
 3
 3
 —%
Real estate funds —
 —
 7
 7
 1%
  $194
 $334
 $10
 $538
 100%
  December 31, 2010 Asset Allocation
  Level 1 Level 2 Level 3 Total 
  (In millions)  
Cash and short-term securities $—
 $16
 $—
 $16
 2%
Equity investment          
Domestic 178
 6
 —
 184
 36%
International 20
 19
 —
 39
 9%
Mutual funds 7
 2
 —
 9
 2%
Fixed income          
U.S. treasuries —
 27
 —
 27
 5%
Government bonds —
 143
 —
 143
 28%
Corporate bonds —
 55
 —
 55
 10%
Distressed debt —
 3
 —
 3
 1%
Mortgage-backed securities (non-government) —
 4
 —
 4
 1%
Alternatives          
Hedge funds —
 15
 —
 15
 3%
Private equity funds —
 —
 3
 3
 1%
Real estate funds —
 —
 9
 9
 2%
  $205
 $290
 $12
 $507
 100%


  December 31, 2009  Asset 
  Level 1  Level 2  Level 3  Total   Allocation 
Assets (in millions)    
Short-term securities $-  $19  $-  $19   4%
Common and preferred stocks  172   53   -   225   47%
Mutual funds  10   2   -   12   3%
Bonds  -   208   -   208   44%
Real estate/other assets  -   -   11   11   2%
  $182  $282  $11  $475   100%
200


The following table provides a reconciliation of changes in the fair value of the other postretirement benefitOPEB trust investments classified as Level 3 in the fair value hierarchy during 2009:2011 and 2010:

  Real estate / Other assets 
  (in millions) 
Beginning balance $12 
Transfers  1 
Acquisitions/(Dispositions)  1 
Loss  (3)
Ending balance $11 

195
  Private Equity Funds Real Estate Funds
  (in millions)
Balance as of January 1, 2010 $4
 $7
Actual return on plan assets:    
Unrealized gains (losses) —
 —
Realized gains (losses) —
 2
Purchases, sales and settlements (1) —
Transfers in (out) —
 —
Balance as of December 31, 2010 3
 9
Actual return on plan assets:    
Unrealized gains —
 1
Realized gains (losses) —
 —
Purchases, sales and settlements —
 —
Transfers in (out) —
 (3)
Balance as of December 31, 2011 $3
 $7

In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pensionpensions and other postretirement benefitOPEB obligations. The assumed rates of return on pension plan assets consider historical market returns and economic forecasts for the types of investments held by FirstEnergy'sFirstEnergy’s pension trusts. The long-term rate of return is developed considering the portfolio’s asset allocation strategy.

FirstEnergy generally employsfollows a total return investment approach wherebyusing a mix of equities, and fixed income and other available investments are usedwhile taking into account the pension plan liabilities to maximizeoptimize the long-term return on plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments. Equity investments are diversified across U.S. and non-U.S. stocks, as well as growth, value, and small and large capitalization funds. Other assets such as real estate and private equity are used to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives are not used to leverage the portfolio beyond the market value of the underlying investments. Investment risk is measured and monitored on a continuing basis through periodic investment portfolio reviews, annual liability measurements and periodic asset/liability studies.

FirstEnergy’s target asset allocations for its pensionpensions and OPEB portfoliotrust portfolios for 20092011 and 20082010 are shown in the following table:
  Target Asset Allocations
  2011 2010
Equities 23% 21%
Fixed income 50
 50
Absolute return strategies 19
 21
Real estate 6
 6
Private equity 2
 2
  100% 100%
  As of December 31,
Assumed Health Care Cost Trend Rates 2011 2010
Health care cost trend rate assumed (pre/post-Medicare) 7.5-8.5%
 8.0-9.0%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) 5% 5%
Year that the rate reaches the ultimate trend rate (pre/post-Medicare) 2016-2018
 2016-2018


  Target Asset Allocations 
  2009  2008 
Equities  58%  58%
Fixed income  30%  30%
Real estate  8%  8%
Private equity  4%  4%
Total  100%  100%
201
Assumed Health Care Cost Trend Rates As of December 31
 2009  2008 
Health care cost trend rate assumed for next year (pre/post-Medicare)
  8.5-10%  8.5-10%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)  5%  5%
Year that the rate reaches the ultimate trend rate (pre/post-Medicare)
  2016-2018   2015-2017 


Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

 1-Percentage-  1-Percentage- 
 Point Increase  Point Decrease  1-Percentage-Point Increase 1-Percentage-Point Decrease
 (In millions)  (in millions)
Effect on total of service and interest cost
 $3  $(2) 2
 (2)
Effect on accumulated postretirement benefit obligation
 $20  $(18)
Effect on accumulated benefit obligation 20
 (17)
Taking into account estimated employee future service, FirstEnergy expects to make the following pension benefit payments from plan assets and other benefit payments, net of the Medicare subsidy and participant contributions:

  Pension  Other 
  Benefits  Benefits 
  (In millions) 
2010
 $316  $85 
2011
  324   87 
2012
  336   58 
2013
  346   51 
2014
  364   53 
Years 2015- 2019
  1,999   273 

196
  Pensions OPEB
  (in millions)
2012 $417
 $111
2013 433
 116
2014 461
 118
2015 479
 62
2016 493
 63
Years 2017-2021 2,713
 314
FES’ and the Utility Registrants' shares of the net pensions and OPEB asset (liability) as of December 31, 2011 and 2010, were as follows:
Net Pension and OPEB Asset (Liability) Pensions OPEB
 2011 2010 2011 2010
  (In millions)
FES $(653) $(488) $(11) $(36)
OE (4) 29
 (75) (66)
CEI (12) (22) (61) (62)
TE 11
 (21) (45) (46)
JCP&L (69) (106) (94) (70)
Met-Ed (6) (6) (31) (19)
Penelec (151) (99) (108) (85)
FES’ and the Utility Registrants' shares of the net periodic pensions and OPEB costs for the three years ended December 31, 2011, 2010 and 2009 were as follows:
Net Periodic Pension and OPEB Costs Pensions OPEB
 2011 2010 2009 2011 2010 2009
  (In millions)
FES $168
 $122
 $169
 $(42) $(12) $—
OE 63
 4
 38
 (34) (26) (30)
CEI 27
 10
 74
 (18) (9) (10)
TE 14
 6
 26
 (7) (6) (2)
JCP&L 68
 29
 49
 2
 (10) (3)
Met-Ed 35
 12
 29
 (9) (24) (15)
Penelec 52
 19
 76
 (7) (24) (14)

4. STOCK-BASED COMPENSATION PLANS

FirstEnergy has four stock-based compensation programs –- LTIP, EDCP, ESOP and DCPD. In 2001, FirstEnergy also assumed responsibility for twoDCPD, as described further below. Allegheny's stock-based plans as a result of its acquisition of GPU. No further stock-based compensation can be awarded under GPU’s Stock Option and Restricted Stock Plan for MYR Group Inc. Employees (MYR Plan) or 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries (GPU Plan). All options and restricted stock under both plans have beenawards were converted into FirstEnergy optionsstock-based awards as of the date of the merger. These awards, referred to below as converted Allegheny awards, were adjusted in terms of the number of awards and, restrictedwhere applicable, the exercise price thereof, to reflect the merger's common stock exchange ratio of 0.667 of a share of FE common stock for each share of AE common stock. Options under the GPU Plan became fully vested on November 7, 2001, and will expire on or before June 1, 2010.


(A)LTIP
202


FirstEnergy’sLTIP
The LTIP includes four forms of stock-based compensation programs –— restricted stock, restricted stock units, stock options and performance shares.

Under FirstEnergy’sthe LTIP, total awards cannot exceed 29.1 million shares of common stock or their equivalent. Only stock options, restricted stock and restricted stock units have currently been designated to pay out in common stock, with vesting periods ranging from two months to ten years.years. Performance share awards are currently designated to be paid in cash rather than common stock and therefore do not count against the limit on stock-based awards. As of December 31, 2009, 7.92011, 5.6 million shares were available for future awards.

FirstEnergy records the actual tax benefit realized forfrom tax deductions when awards are exercised or distributed. Realized tax benefits during the years ended December 31, 2009, 2008,2011, 2010 and 20072009 were $9$14 million $43, $11 million and $34$9 million, respectively. The excess of the deductible amount over the recognized compensation cost is recorded toas a component of stockholders’ equity and reported as an other financing activity withinon the Consolidated Statements of Cash Flows.

Restricted Stock and Restricted Stock Units
Restricted common stock (restricted stock) and restricted stock units (stock units) activity for the year ended December 31, 2011, was as follows:
Restricted stock and stock units outstanding as of January 1, 20111,878,022
Granted915,054
Converted AE restricted stock645,197
Exercised(984,543)
Forfeited(100,596)
Restricted stock and stock units outstanding as of December 31, 20112,353,134
The 915,054 shares of restricted stock granted during the year ended December 31, 2011, had a grant-date fair value of $34 million and a weighted-average vesting period of 2.76 years.
Eligible employees receive awards of FirstEnergy commonFE restricted stock or stock units subject to restrictions. Those restrictions that lapse over a defined period of time or based on performance.upon achieving performance results. Dividends are received on the restricted stock and are reinvested in additional shares. Restricted common stock grants under the LTIP were as follows:

 2009  2008  2007 
Restricted common shares granted  73,255   82,607   77,388 
 2011 2010 2009
Restricted stock granted 297,859
 71,752
 73,255
Weighted average market price $43.68  $68.98  $67.98  $38.44
 $38.43
 $43.68
Weighted average vesting period (years)  4.42   5.03   4.61  2.27
 4.74
 4.42
Dividends restricted Yes  Yes  Yes  Yes
 Yes
 Yes

Vesting activity for restricted common stock during the year2011 was as follows (forfeitures were not material):

    Weighted 
  Number Average 
  of Grant-Date 
Restricted Stock Shares Fair Value 
Nonvested as of January 1, 2009  667,933  $49.54 
Nonvested as of December 31, 2009  648,293   48.84 
Granted in 2009  73,255   43.68 
Vested in 2009  85,881   42.73 
Restricted Stock Number of Shares Weighted Average Grant-Date Fair Value
Nonvested as of January 1, 2011 475,914
 $51.26
Nonvested as of December 31, 2011 654,696
 $45.26
Granted in 2011 297,859
 $38.44
Vested in 2011 121,573
 $41.10

FirstEnergy grants two types of restricted stock unit awards: discretionary-based and performance-based. With theThe discretionary-based FirstEnergy grantsawards grant the right to receive, at the end of the period of restriction, a number of shares of common stock equal to the number of restricted stock units set forth in each agreement. With the performance-based, FirstEnergy grantsPerformance-based awards grant the right to receive, at the end of the period of restriction, a number of shares of common stock equal to the number of restricted stock units set forth in the agreement subject to adjustment based on FirstEnergy’s stock performance.FirstEnergy's performance relative to financial and operational performance targets.
  2011 2010 2009
Restricted stock units granted 617,195
 511,418
 533,399
Weighted average vesting period (years) 3.00
 3.00
 3.00


  2009  2008  2007 
Restricted common share units granted  533,399   450,683   412,426 
Weighted average vesting period (years)  3.00   3.14   3.22 
203

197


Vesting activity for restricted stock units during the year2011 was as follows (forfeitures were not material):

    Weighted 
  Number Average 
  of Grant-Date 
Restricted Stock Units Shares Fair Value 
Nonvested as of January 1, 2009  1,011,054  $62.02 
Nonvested as of December 31, 2009  1,031,050   60.10 
Granted in 2009  533,399   41.40 
Vested in 2009  457,536   42.53 
Restricted Stock Units Number of Shares Weighted Average Grant-Date Fair Value
Nonvested as of January 1, 2011 1,402,108
 $48.40
Nonvested as of December 31, 2011 1,566,679
 $40.20
Granted in 2011 617,195
 $36.80
Vested in 2011 444,818
 $37.37

Compensation expense recognized in 2009, 20082011, 2010 and 20072009 for restricted stock and restricted stock units, net of amounts capitalized, was approximately $25$65 million $29, $22 million and $24$25 million, respectively.

Stock Options

Stock options were granted to eligible employees allowing them to purchase a specified number of common shares at a fixed grant price over a defined period of time. Stock option activities under FirstEnergy stock option programs for 2009 wereactivity during 2011 was as follows:

     Weighted 
  Number  Average 
  of  Exercise 
Stock Option Activities Options  Price 
Balance, January 1, 2009
  3,266,408  $34.56 
(3,266,408 options exercisable)
        
         
Options granted
  -   - 
Options exercised
  178,133   32.53 
Options forfeited
  21,075   30.50 
Balance, December 31, 2009
  3,067,200  $34.70 
(3,067,200 options exercisable)
        
Stock Option Activity Number of Shares Weighted Average Grant-Date Fair Value
Balance, January 1, 2011 (2,889,066 options exercisable) 2,889,066
 $35.18
Options granted 662,122
 37.75
Converted Allegheny options 1,805,811
 41.75
Options exercised (973,817) 31.48
Options forfeited (127,197) 70.19
Balance, December 31, 2011 (3,593,863 options exercisable) 4,255,985
—
$38.17

The options granted during the year ended December 31, 2011, had a grant-date fair value of $3 million and an expected weighted-average vesting period of 3.79 years.
Options outstanding by plan and range of exercise priceprices as of December 31, 20092011, were as follows:

     
Options Outstanding and Exercisable
 
        Weighted    
  Range of     Average  Remaining 
Program
 
Exercise Prices
  
Shares
  
Exercise Price
  
Contractual Life
 
FE Plan $19.31 - $29.87   1,040,749  $29.22   2.34 
  $30.17 - $39.46   2,010,104  $37.63   3.67 
GPU Plan $23.75 - $35.92   16,347  $23.75   0.42 
Total      3,067,200  $34.70   3.20 
  Options Outstanding and Exercisable
Range of Exercise Prices Shares Weighted Average Exercise Price Remaining Contractual Life
$20.02-$30.74 959,752
 $26.88
 1.50
$30.74-$40.93 2,962,802
 $37.42
 3.79
$42.72-$51.82 415
 $44.35
 2.16
$53.06-$62.97 33,215
 $54.11
 3.34
$64.52-$71.82 6,670
 $68.44
 4.99
$73.38-$80.47 291,797
 $80.22
 3.44
$81.19-$89.59 1,334
 $81.19
 5.33
Total 4,255,985
 $38.17
 $3.25

FirstEnergy reduced its use ofCompensation expense recognized for stock options beginning in 2005 and increased its use of performance-based, restricted stock units. As a result, all unvested stock options vested in 2008.during 2011 was $0.8 million. No compensation expense was recognized for stock options during 2009,2010 and compensation expense in 2008 and 2007 was not material.2009. Cash received from the exercise of stock options in 2009, 20082011, 2010 and 20072009 was $7$32 million $74, $6 million and $88$7 million, respectively.

Performance Shares

Performance shares are share equivalents and do not have voting rights. The shares track the performance of FirstEnergy'sFE's common stock over a three-year vesting period. During that time, dividend equivalents are converted into additional shares. The final account value may be adjusted based on the ranking of FirstEnergyFE stock performance to a composite of peer companies. Compensation expense (credits) recognized for performance shares during 2009, 20082011, 2010 and 2007,2009, net of amounts capitalized, totaled approximately $3$2 million $8, ($4) million and $20$3 million, respectively. During 2011 and 2010, no cash was paid to settle performance shares due to certain criteria not being met for the previous three-year vesting period. Cash used to settle performance shares in 2009 2008 and 2007 was $15$15 million $14 million and $10 million, respectively..


(B)   ESOP204


ESOP
An ESOP Trust funded most of the matching contribution for FirstEnergy'sFirstEnergy’s 401(k) savings plan through December 31, 2007. All employees eligible for participation in the 401(k) savings plan are covered by the ESOP. Between 1990
In 2011, 2010 and 1991, the ESOP borrowed $200 million from OE and acquired 10,654,1142009, shares of OE's common stock (subsequently converted to FirstEnergy common stock) through market purchases. The ESOP loan was paid in full in 2008.

198

In 2008 and 2009, shares of FirstEnergyFE common stock were purchased on the market and contributed to participants’ accounts. Total ESOP-related compensation expenses in 2009, 20082011, 2010 and 2007,2009, net of amounts capitalized and dividends on common stock, were $36$55 million $40, $30 million and $28$36 million, respectively.

(C)   EDCP

Under the EDCP, covered employees can direct a portion of their compensation, including annual incentive awards and/or long-term incentive awards, into an unfunded FirstEnergyFE stock account to receive vested stock units or into an unfunded retirement cash account. AnThrough December 31, 2010, covered employees received an additional 20% premium is received in the form of stock units based on the amount allocated to the FirstEnergy stock account. During 2010, the EDCP was amended to cease the 20% stock premium with respect to annual and long-term incentive awards earned during any calendar years that commence on or after January 1, 2011. Dividends are calculated quarterly on stock units outstanding and are paid in the form of additional stock units. Upon withdrawal, stock units are converted to FirstEnergyFE shares. Payout typically occurs three years from the date of deferral; however, an election can be made in the year prior to payout to further defer shares into a retirement stock account that will pay out in cash upon retirement (see Note 3)3, Pension and Other Postemployment Benefit). Interest is calculated on the cash allocated to the cash account and the total balance will pay out in cash upon retirement. Of the 1.3 million EDCP stock units authorized, 481,028 stock units were available for future awards as of December 31, 2009. Compensation expense (income)expenses (credits) recognized on EDCP stock units, net of amounts capitalized, was not material in 2009, ($13) million in 20082011, 2010 and $72009 were $4 million in 2007,, ($3) million and ($0.2) million, respectively.

DCPD
(D)DCPD

Under the DCPD, directorsmembers of the Board of Directors can elect to allocate all or a portion of their cash retainers, meeting fees and chair fees to deferred stock or deferred cash accounts. If the funds areFunds deferred into the stock account through December 31, 2010, received a 20% match is added to the funds allocated. The 20% match and any appreciation on it are forfeited if the director leaves the Board within three years from the date of deferral for any reason other than retirement, disability, death, upon a change in control or when a director is ineligible to stand for re-election. Compensation expense is recognized for the 20% match over the three-year vesting period. Directors may also elect to defer their equity retainers into the deferred stock account; however, they do not receive a 20% match on that deferral. During 2010, the DCPD was amended to cease the 20% match feature with respect to director’s fees earned for service performed during any calendar years that commence on or after January 1, 2011. DCPD expenses recognized in each of 2009, 20082011, 2010 and 20072009 were approximately $3 million.$4 million, $4 million and $3 million, respectively. The net liability recognized for DCPD of approximately $5$6 million as of December 31, 2011, and $5 million as of December 31, 2009, 20082010 and 20072009, is included in the caption “Retirement benefits” on the Consolidated Balance Sheets.
Of the 1.7 million stock units authorized under the EDCP and DCPD, 1,075,080 stock units were available for future awards as of December 31, 2011.
5. TAXES
Income Taxes
FirstEnergy records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to temporary tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled. Details of income taxes for the three years ended December 31, 2011 are shown below:


205


PROVISION FOR INCOME TAXES FirstEnergy FES OE CEI TE JCP&L Met-Ed Penelec
  (In millions)
2011                
Currently payable (receivable)-                
Federal $(243) $(219) $13
 $17
 $(15) $19
 $26
 $(36)
State 19
 9
 (12) (7) (6) 7
 7
 (6)
  (224) (210) 1
 10
 (21) 26
 33
 (42)
Deferred, net-                
Federal 785
 206
 65
 15
 35
 71
 14
 75
State 24
 (3) 13
 10
 1
 20
 (10) (3)
  809
 203
 78
 25
 36
 91
 4
 72
Investment tax credit amortization (11) (4) (1) (1) —
 —
 —
 —
Total provision for income taxes $574
 $(11) $78
 $34
 $15
 $117
 $37
 30
                 
2010                
Currently payable (receivable)-                
Federal $(23) $(23) $37
 $58
 $(8) $80
 $1
 $(81)
State 35
 (2) (2) 1
 (2) 36
 12
 (12)
  12
 (25) 35
 59
 (10) 116
 13
 (93)
Deferred, net-                
Federal 432
 142
 41
 (19) 25
 30
 37
 122
State 27
 12
 3
 (4) 1
 1
 (2) 18
  459
 154
 44
 (23) 26
 31
 35
 140
Investment tax credit amortization (9) (4) (1) (1) —
 —
 —
 (1)
Total provision for income taxes $462
 $125
 $78
 $35
 $16
 $147
 $48
 $46
                 
2009                
Currently payable (receivable)-                
Federal $(183) $87
 $21
 $40
 $6
 $40
 $(34) $(21)
State 44
 8
 4
 2
 —
 26
 (4) 4
  (139) 95
 25
 42
 6
 66
 (38) (17)
Deferred, net-                
Federal 296
 169
 36
 (62) (3) 38
 60
 55
State 36
 21
 3
 1
 2
 1
 7
 2
  332
 190
 39
 (61) (1) 39
 67
 57
Investment tax credit amortization (9) (4) (2) (1) —
 —
 —
 (1)
Total provision for income taxes $184
 $281
 $62
 $(20) $5
 $105
 $29
 $39
In 2011, an unregulated subsidiary of FirstEnergy elected to be taxed as a limited liability company, which improved its future taxable income and resulted in reversing a portion of its valuation allowance previously established for state income tax benefits. The reversal of the valuation allowance reduced income tax expense by $27 million.
As a result of the Patient Protection and Affordable Care Act and the Health Care and Education Affordability Reconciliation Act signed into law in March 2010, beginning in 2013 the tax deduction currently available to FirstEnergy will 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 under prior law were already reflected in FirstEnergy’s consolidated financial statements, the change resulted in a charge to FirstEnergy’s earnings in 2010 of approximately $13 million and a reduction in accumulated deferred tax assets associated with these subsidies. This change reflects the anticipated increase in income taxes that will occur as a result of the change in tax law.
FES and the Utilities are party to an intercompany income tax allocation agreement with FirstEnergy and its other subsidiaries that provides for the allocation of consolidated tax liabilities. Net tax benefits attributable to FirstEnergy, excluding any tax benefits derived from interest expense associated with acquisition indebtedness from the merger with GPU, are reallocated to the subsidiaries of FirstEnergy that have taxable income. That allocation is accounted for as a capital contribution to the company receiving the tax benefit.


206


The following tables provide a reconciliation of federal income tax expense at the federal statutory rate to the total provision for income taxes for the three years ended December 31, 2011.
 FirstEnergy FES OE CEI TE JCP&L Met-Ed Penelec
 (In millions)
2011               
Book income (loss) before provision for income taxes$1,459
 $(70) $206
 $104
 $49
 $261
 $105
 $93
Federal income tax expense at statutory rate$511
 $(25) $72
 $36
 $17
 $91
 $37
 $33
Increases (reductions) in taxes resulting from-               
Amortization of investment tax credits(11) (4) (1) (1) —
 —
 —
 —
State income taxes, net of federal tax benefit28
 4
 1
 2
 (3) 18
 (2) (6)
State unitary tax adjustments33
 —
 —
 —
 —
 —
 —
 —
Manufacturing deduction16
 13
 3
 1
 —
 —
 —
 —
Medicare Part D36
 4
 6
 3
 1
 6
 5
 6
Effectively settled tax items(11) (2) (3) (3) (3) —
 —
 —
State valuation allowance(19) 2
 —
 —
 —
 —
 —
 (4)
Other, net(9) (3) —
 (4) 3
 2
 (3) 1
Total provision for income taxes$574
 $(11) $78
 $34
 $15
 $117
 $37
 $30
2010               
Book income before provision for income taxes$1,204
 $356
 $233
 $111
 $52
 $330
 $108
 $110
Federal income tax expense at statutory rate$421
 $125
 $82
 $39
 $18
 $116
 $38
 $39
Increases (reductions) in taxes resulting from-               
Amortization of investment tax credits(9) (4) (1) (1) —
 —
 —
 (1)
State income taxes, net of federal tax benefit40
 7
 1
 (2) (1) 24
 7
 4
Manufacturing deduction—
 2
 (2) —
 —
 —
 —
 —
Medicare Part D17
 1
 2
 1
 —
 4
 2
 3
Effectively settled tax items(34) (2) (9) (4) (3) —
 —
 —
State valuation allowance—
 2
 —
 —
 —
 —
 —
 (1)
Other, net27
 (6) 5
 2
 2
 3
 1
 2
Total provision for income taxes$462
 $125
 $78
 $35
 $16
 $147
 $48
 $46
2009               
Book income (loss) before provision for income taxes$1,056
 $779
 $181
 $(50) $24
 $263
 $82
 $89
Federal income tax expense at statutory rate$370
 $273
 $63
 $(18) $8
 $92
 $29
 $31
Increases (reductions) in taxes resulting from-               
Amortization of investment tax credits(9) (4) (2) (1) —
 —
 —
 (1)
State income taxes, net of federal tax benefit52
 19
 5
 2
 1
 18
 2
 4
Manufacturing deduction(13) (11) (2) 1
 (1) —
 —
 —
Medicare Part D14
 7
 (1) —
 —
 2
 1
 2
Effectively settled tax items(217) —
 —
 —
 —
 —
 —
 —
State valuation allowance(1) 3
 —
 —
 —
 —
 —
 (2)
Other, net(12) (6) (1) (4) (3) (7) (3) 5
Total provision for income taxes$184
 $281
 $62
 $(20) $5
 $105
 $29
 $39


207


Accumulated deferred income taxes as of December 31, 2011 and 2010 are as follows:
  FirstEnergy FES OE CEI TE JCP&L Met-Ed Penelec
  (In millions)
December 31, 2011                
Property basis differences $6,738
 $770
 $673
 $527
 $206
 $792
 $457
 $577
Regulatory transition charge 105
 —
 30
 73
 5
 49
 2
 —
Customer receivables for future income taxes 125
 —
 —
 —
 —
 12
 55
 58
Deferred MISO/PJM transmission costs 51
 —
 —
 —
 —
 —
 34
 17
Other regulatory assets — RCP 165
 —
 82
 55
 28
 —
 —
 —
Deferred sale and leaseback gain (450) (398) (31) —
 —
 (10) (12) —
Nonutility generation costs 36
 —
 —
 —
 —
 (2) 31
 7
Unamortized investment tax credits (72) (19) (3) (4) (2) (2) (4) (4)
Unrealized losses on derivative hedges (21) 5
 —
 —
 —
 (1) —
 —
Pensions and OPEB (752) (85) (76) (36) (18) (75) (24) (114)
Lease market valuation liability (179) (65) —
 —
 (68) —
 —
 —
Oyster Creek securitization (Note 12) 93
 —
 —
 —
 —
 93
 —
 —
Nuclear decommissioning activities 123
 108
 15
 —
 17
 (7) 7
 (17)
Mark-to-market adjustments (7) (7) —
 —
 —
 —
��—
 —
Deferred gain for asset sales — affiliated companies —
 —
 31
 20
 7
 —
 —
 —
Equity investments 132
 —
 —
 —
 —
 —
 —
 —
Loss carryforwards and AMT credits (612) (34) —
 —
 —
 —
 (6) (30)
Loss carryforward valuation reserve 34
 12
 —
 —
 —
 —
 —
 7
All other 161
 (1) 66
 28
 (5) 10
 —
 (2)
Net deferred income tax liability $5,670
 $286
 $787
 $663
 $170
 $859
 $540
 $499
                 
December 31, 2010                
Property basis differences $3,910
 $650
 $625
 $496
 $206
 $728
 $407
 $504
Regulatory transition charge 235
 12
 37
 89
 3
 95
 (1) —
Customer receivables for future income taxes 113
 —
 —
 —
 —
 13
 48
 52
Deferred MISO/PJM transmission costs 85
 —
 —
 —
 —
 —
 62
 23
Other regulatory assets — RCP 166
 —
 82
 56
 28
 —
 —
 —
Deferred sale and leaseback gain (469) (412) (35) —
 —
 (10) (12) —
Nonutility generation costs 51
 —
 —
 —
 —
 —
 55
 (4)
Unamortized investment tax credits (44) (20) (4) (4) (2) (2) (5) (4)
Unrealized losses on derivative hedges (29) —
 —
 —
 —
 —
 —
 —
Pensions and OPEB (686) (96) (58) (32) (28) (74) (13) (80)
Lease market valuation liability (197) (82) —
 —
 (81) —
 —
 —
Oyster Creek securitization (Note 12) 109
 —
 —
 —
 —
 109
 —
 —
Nuclear decommissioning activities 47
 79
 7
 (1) 15
 (8) 2
 (47)
Mark-to-market adjustments (42) (42) —
 —
 —
 —
 —
 —
Deferred gain for asset sales — affiliated companies —
 —
 34
 22
 7
 —
 —
 —
Loss carryforwards (41) (10) —
 —
 —
 —
 —
 (23)
Loss carryforward valuation reserve 26
 9
 —
 —
 —
 —
 —
 11
All other (74) (21) 49
 21
 (7) (58) (17) 6
Net deferred income tax liability $3,160
 $67
 $737
 $647
 $141
 $793
 $526
 $438
FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. Accounting guidance prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of tax positions taken or expected to be taken on a company’s tax return. As a result of the merger with AE in 2011, FirstEnergy's unrecognized income tax benefits increased by $97 million. FirstEnergy also reached a settlement with the IRS on a research and development claim and recognized approximately $30 million of income tax benefits, including $5 million that favorably affected FirstEnergy's effective tax rate in 2011. The IRS issued guidance in 2011 providing a safe harbor method of tax accounting for electric transmission and distribution property (see discussion below) to determine the tax treatment of repair costs for electric transmission and distribution assets. FirstEnergy is evaluating the method change for this temporary tax item and, if elected, is not expected to be material to the financial position or effective tax rates of FirstEnergy and the Utilities.


208


After reaching settlements on appeal in 2010 related primarily to the capitalization of certain costs for the tax years 2004-2008 and an unrelated federal tax matter related to prior year gains and losses recognized from the disposition of assets, as well as receiving final approval from the Joint Committee on Taxation for several items that were under appeal for tax years 2001-2003, FirstEnergy recognized approximately $78 million of net tax benefits in 2010, including $21 million$0 millionthat favorably affected FirstEnergy’s effective tax rate. The remaining portion of the tax benefit increased FirstEnergy’s accumulated deferred income taxes.
Upon reaching a settlement on several items under appeal for the tax years 2001-2003, as well as other items that effectively settled in 2009, FirstEnergy recognized approximately $100 million of net tax benefits, including $161 million that favorably affected FirstEnergy’s 2009 effective tax rate. The offsetting $61 million primarily related to tax items where the uncertainty was removed and the tax refund was received.
As of December 31, 2011, it is reasonably possible that approximately $44 million of unrecognized tax benefits may be resolved during 2012, of which up to approximately $10 million, if recognized, would affect FirstEnergy’s effective tax rate. The potential decrease in the amount of unrecognized tax benefits is primarily associated with issues related to the capitalization of certain costs and various state tax items.
In 2009, FirstEnergy, on behalf of the Utilities, filed a change in accounting method related to the costs to repair and maintain electric utility network (transmission and distribution) assets. In 2010, approximately $325 million of costs were included as a repair deduction on FirstEnergy’s 2009 consolidated federal income tax return, which reduced taxable income and increased the amount of tax refunds that were applied to FirstEnergy’s 2010 estimated federal tax payments. Due to the flow through of the Pennsylvania state income tax benefit for this change in accounting, FirstEnergy’s effective tax rate was reduced by $6 million in 2010. In connection with completing FirstEnergy’s 2009 consolidated tax return, FES recognized an $8 million adjustment that increased its income tax expense in 2010.
In 2008, FirstEnergy, on behalf of FGCO and NGC, filed a change in accounting method related to the costs to repair and maintain electric generation stations. During the second quarter of 2009, the IRS approved the change in accounting method and $281 million of costs were included as a repair deduction on FirstEnergy’s 2008 consolidated federal income 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 2009.
The following table summarizes the changes in unrecognized tax positions for the years ended 2011, 2010 and 2009.
  FirstEnergy FES OE CEI TE JCP&L Met-Ed Penelec
  (In millions)
Balance, January 1, 2009 $219
 $5
 $(30) $(26) $(4) $42
 $28
 $24
Current year increases 41
 34
 4
 3
 —
 —
 —
 —
Prior years increases 46
 2
 103
 52
 10
 —
 —
 —
Prior years decreases (100) —
 —
 —
 —
 (28) (15) (13)
Decrease for settlement (15) —
 —
 —
 —
 —
 —
 —
Balance, December 31, 2009 $191
 $41
 $77
 $29
 $6
 $14
 $13
 $11
Current year increases 10
 6
 2
 (1) —
 —
 2
 1
Prior years increases 2
 —
 —
 —
 —
 —
 —
 —
Prior years decreases (81) (4) (19) (15) (6) (21) (2) (5)
Decrease for settlement (77) (2) (58) (14) —
 7
 (11) (6)
Balance, December 31, 2010 $45
 $41
 $2
 $(1) $—
 $—
 $2
 $1
Increase due to merger with AE 97
 —
 —
 —
 —
 —
 —
 —
Prior years increases 10
 8
 —
 1
 —
 —
 —
 —
Prior years decreases (35) (4) (2) —
 —
 —
 (2) (1)
Balance, December 31, 2011 $117
 $45
 $—
 $—
 $—
 $—
 $—
 $—
FirstEnergy 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 federal income tax return. FirstEnergy includes net interest and penalties in the provision for income taxes. As a result of the merger with AE in 2011, the amount of accrued interest increased by $6 million. The interest associated with the 2011 settlement of the claim favorably affected FirstEnergy's effective tax rate by $7 million in 2011. The reversal of accrued interest associated with the recognized tax benefits favorably affected FirstEnergy’s effective tax rate by $12 million in 2010. The reversal of accrued interest associated with the $161 million in recognized tax benefits favorably affected FirstEnergy’s effective tax rate in 2009 by $56 million.


209


The following table summarizes the net interest expense (income) for the three years ended December 31, 2011 and the cumulative net interest payable (receivable) as of December 31, 2011 and 2010:
  
Net Interest Expense (Income)
For the Years Ended December 31,
 
Net Interest Payable
As of December 31,
  2011 2010 2009 2011 2010
  (In millions) (In millions)
FirstEnergy $(5) $(10) $(49) $11
 $3
FES 1
 1
 (1) 4
 2
OE (2) (3) 4
 1
 1
CEI (2) (2) 3
 —
 —
TE (1) (1) —
 —
 —
JCP&L —
 (2) (4) —
 —
Met-Ed —
 —
 (2) —
 —
Penelec —
 —
 (1) —
 —

5.FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS (2008-2010) and state tax authorities. FirstEnergy's tax returns for all state jurisdictions are open from 2008-2010, as well as 2005-2007 for New Jersey. The IRS completed its audits of tax year 2008 in July 2010 and tax year 2009 in April 2011, with both tax years having one item under appeal. Tax years 2010-2011 are under review by the IRS. Allegheny is currently under audit by the IRS for tax years 2007 and 2008. Allegheny has filed its 2010 and 2009 federal returns and such filings are subject to review. State tax returns for tax years 2008 through 2010 remain subject to review in Pennsylvania, West Virginia, Maryland and Virginia for certain subsidiaries of AE. Management believes that adequate reserves have been recognized and final settlement of these audits is not expected to have a material adverse effect on FirstEnergy's financial condition, results of operations, cash flow or liquidity.

FirstEnergy has recorded as deferred income tax assets the effect of net operating losses and tax credits that will more likely than not be realized through future operations and through the reversal of existing temporary differences. In 2011, the tax benefit of operating loss carryforwards included in deferred income tax expense was $344 million. As of December 31, 2011, the deferred income tax assets, before any valuation allowances, consisted of $286 million of federal net operating loss carryforwards that expire from 2024 to 2031, federal AMT credits of $25 million that have an indefinite carryforward period and $301 million of state and local net operating loss carryforwards that begin to expire in 2012.
FirstEnergy has pre-tax net operating loss carryforwards for state and local income tax purposes of approximately $12.9 billion, of which $11.8 billion is expected to be utilized. The associated deferred tax assets, net of valuation reserves, are $267 million. These losses expire as follows:
Expiration Period FirstEnergy FES Penelec
  (In millions)
2012-2016 $885
 $644
 $—
2017-2021 901
 33
 119
2022-2026 8,402
 4
 94
2027-2031 2,675
 408
 257
  $12,863
 $1,089
 $470


210


General Taxes
Details of general taxes for the years ended 2011, 2010 and 2009, are shown below:
  FirstEnergy FES OE CEI TE JCP&L Met-Ed Penelec
  (In millions)
2011                
KWH excise $244
 $—
 $90
 $66
 $27
 $50
 $—
 $—
State gross receipts 264
 62
 17
 2
 1
 —
 64
 55
Real and personal property 299
 42
 73
 80
 23
 6
 2
 2
Social security and unemployment 109
 14
 9
 6
 3
 11
 5
 6
Other 62
 6
 1
 —
 —
 —
 3
 3
Total general taxes $978
 $124
 $190
 $154
 $54
 $67
 $74
 $66
2010                
KWH excise $245
 $5
 $92
 $68
 $27
 $51
 $—
 $—
State gross receipts 185
 17
 15
 —
 —
 —
 85
 68
Real and personal property 243
 53
 67
 70
 23
 5
 —
 (1)
Social security and unemployment 86
 14
 8
 5
 2
 9
 4
 5
Other 17
 5
 1
 —
 —
 —
 (1) 1
Total general taxes $776
 $94
 $183
 $143
 $52
 $65
 $88
 $73
2009                
KWH excise(1)
 $224
 $1
 $84
 $66
 $24
 $49
 $—
 $—
State gross receipts 171
 14
 15
 —
 —
 —
 78
 63
Real and personal property 253
 53
 64
 74
 21
 5
 2
 2
Social security and unemployment 90
 14
 8
 5
 3
 9
 5
 6
Other 15
 5
 —
 —
 —
 —
 3
 3
Total general taxes $753
 $87
 $171
 $145
 $48
 $63
 $88
 $74
(1)
KWH excise tax for OE and TE include $7 million and $3 million credit adjustments, respectively, recognized in 2009 related to prior periods.
6. LEASES
FirstEnergy leases certain generating facilities, office space and other property and equipment under cancelable and noncancelable leases.
In 1987, OE sold portions of its ownership interests in Perry Unit 1 and Beaver Valley Unit 2 and entered into operating leases on the portions sold for basic lease terms of approximately 29 years. In that same year, CEI and TE also sold portions of their ownership interests in Beaver Valley Unit 2 and Bruce Mansfield Units 1, 2 and 3 and entered into similar operating leases for lease terms of approximately 30 years. During the terms of their respective leases, OE, CEI and TE are responsible, to the extent of their leasehold interests, for costs associated with the units including construction expenditures, operation and maintenance expenses, insurance, nuclear fuel, property taxes and decommissioning. They have the right, at the expiration of the respective basic lease terms, to renew their respective leases. They also have the right to purchase the facilities at the expiration of the basic lease term or any renewal term at a price equal to the fair market value of the facilities. The basic rental payments are adjusted when applicable federal tax law changes.
In 2007, CEI and TE assigned their leasehold interests in the Bruce Mansfield Plant to FGCO, who assumed all of CEI’s and TE’s obligations arising under those leases. However, CEI and TE remain primarily liable on the 1987 leases and related 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.
In 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1 and entered into operating leases for basic lease terms of approximately 33 years. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases.
During 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.


211


Rentals for capital and operating leases for 2011, 2010 and 2009, are summarized as follows:
  FirstEnergy FES OE CEI TE JCP&L Met-Ed Penelec
  (In millions)
2011                
Operating leases $226
 $197
 $147
 $4
 $64
 $8
 $4
 $4
Capital leases                
Interest element 6
 1
 —
 1
 —
 —
 —
 —
Other(1)
 46
 34
 —
 —
 —
 —
 —
 —
Total rentals $278
 $232
 $147
 $5
 $64
 $8
 $4
 $4
                 
2010                
Operating leases $228
 $202
 $147
 $4
 $64
 $9
 $7
 $4
Capital leases                
Interest element 2
 1
 —
 1
 —
 —
 —
 —
Other(1)
 35
 34
 —
 —
 —
 —
 1
 —
Total rentals $265
 $237
 $147
 $5
 $64
 $9
��$8
 $4
                 
2009                
Operating leases $236
 $202
 $146
 $4
 $64
 $9
 $7
 $4
Capital leases                
Interest element 1
 2
 1
 1
 —
 —
 —
 —
Other(1)
 16
 18
 —
 —
 —
 —
 —
 —
Total rentals $253
 $222
 $147
 $5
 $64
 $9
 $7
 $4
(1)
FirstEnergy and FES include $29 million, $30 million and $16 million, in 2011, 2010 and 2009, respectively, for wind purchased power agreements classified as capital leases.
The future minimum capital lease payments as of December 31, 2011 are as follows (TE and JCP&L have no material capital leases):
Capital leases FirstEnergy FES OE CEIMet-Ed Penelec
  (In millions)         
2012 $25
 $6
 $2
 $2
$1
 $1
2013 24
 6
 2
 2
1
 1
2014 22
 6
 2
 2
1
 1
2015 20
 6
 2
 2
1
 1
2016 17
 6
 2
 2
—
 —
Years thereafter 27
 5
 3
 2
—
 —
Total minimum lease payments 135
 35
 13
 12
4
 4
Executory costs —
 —
 —
 —
—
 —
Net minimum lease payments 135
 35
 13
 12
4
 4
Interest portion (27) (4) (2) (4)—
 —
Present value of net minimum lease payments 108
 31
 11
 8
4
 4
Less current portion 23
 5
 1
 1
—
 —
Noncurrent portion $85
 $26
 $10
 $7
$4
 $4
Established by OE in 1996, PNBV purchased a portion of the lease obligation bonds issued on behalf of lessors in OE’s Perry Unit 1 and Beaver Valley Unit 2 sale and leaseback transactions. Similarly, CEI and TE established Shippingport in 1997 to purchase the lease obligation bonds issued on behalf of lessors in their Bruce Mansfield Units 1, 2 and 3 sale and leaseback transactions. The PNBV and Shippingport arrangements effectively reduce lease costs related to those transactions (see Note 8, Variable Interest Entities).


212


FirstEnergy's future minimum consolidated operating lease payments as of December 31, 2011, are as follows:
  FirstEnergy
Operating Leases Lease Payments 
Capital Trust(1)
 Net
  (In millions)
2012 $383
 $125
 $258
2013 382
 130
 252
2014 371
 131
 240
2015 373
 90
 283
2016 344
 29
 315
Years thereafter 1,803
 4
 1,799
Total minimum lease payments $3,656
 $509
 $3,147
(1)
PNBV and Shippingport purchased a portion of the lease obligation bonds associated with certain sale and leaseback transactions. These arrangements effectively reduce lease costs related to those transactions.
Operating Leases FES 
OE(1)
 CEI 
TE(1)
 JCP&L Met-Ed Penelec
  (In millions)
2012 $237
 $147
 $4
 $64
 $7
 $4
 $3
2013 241
 146
 3
 64
 7
 4
 3
2014 236
 145
 3
 64
 6
 3
 2
2015 239
 145
 2
 64
 5
 4
 2
2016 230
 117
 3
 64
 5
 3
 2
Years thereafter 1,662
 49
 4
 14
 48
 37
 12
Total minimum lease payments $2,845
 $749
 $19
 $334
 $78
 $55
 $24
(1)
Includes certain minimum lease payments associated with NGC's lessor equity interests in Perry and Beaver Valley Unit 2 that are eliminated in consolidation.
FirstEnergy recorded above-market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant associated with the 1997 merger between OE and Centerior. The unamortized above-market lease liability for Beaver Valley Unit 2 of $199 million as of December 31, 2011, of which $37 million is classified as current, is being amortized by TE on a straight-line basis through the end of the lease term in 2017. The unamortized above-market lease liability for the Bruce Mansfield Plant of $217 million as of December 31, 2011, of which $46 million is classified as current, is being amortized by FGCO on a straight-line basis through the end of the lease term in 2016.
7. INTANGIBLE ASSETS
As of December 31, 2011, intangible assets classified in Other Deferred Charges on FirstEnergy’s Consolidated Balance Sheet, including those recorded in connection with the Allegheny merger, include the following:
  Intangible Assets Amortization expense
        Actual Estimated
(In millions) Gross Accumulated Amortization Net 2011 2012 2013 2014 2015 2016 Thereafter
NUG contracts(1)(2)
 $124
 $4
 $120
 $4
 $5
 $5
 $5
 $5
 $5
 $95
OVEC(1)
 54
 1
 53
 1
 2
 2
 2
 2
 2
 43
Coal contracts(1)(3)
 516
 74
 442
 56
 55
 53
 52
 45
 45
 108
FES customer contracts 144
 21
 123
 12
 14
 16
 17
 17
 17
 42
Energy contracts(1)
 136
 71
 65
 71
 50
 14
 1
 —
 —
 —
  $974
 $171
 $803
 $144
 $126
 $90
 $77
 $69
 $69
 $288
(1)
Fair value measurements of intangible assets recorded in connection with the Allegheny merger (see Note 2, Merger)
(2)
NUG contracts are subject to regulatory accounting and their amortization does not impact earnings.
(3)
A gross amount of $102 million of the coal contracts was recorded with a regulatory offset and the amortization does not impact earnings. $18 million and $84 million are related to the accumulated amortization and net amounts, respectively.

FES acquired certain customer contract rights which were capitalized as intangible assets. These rights allow FES to supply electric generation to customers, and the recorded value is being amortized ratably over the term of the related contracts.


213


8. VARIABLE INTEREST ENTITIES
FirstEnergy and its subsidiaries perform qualitative analyses 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 or the right to receive benefits from the entity that could potentially be significant to the VIE.
VIEs included in FirstEnergy's consolidated financial statements are: FEV's joint venture in the Signal Peak mining and coal transportation operations, a portion of which was sold on October 18, 2011, and resulted in deconsolidation; the PNBV and Shippingport bond trusts that were created to refinance debt originally issued in connection with sale and leaseback transactions; wholly 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 and JCP&L's supply of BGS, of which $287 million was outstanding as of December 31, 2011; and special purpose limited liabilities companies of MP and PE created to issue environmental control bonds that were used to construct environmental control facilities, of which $513 million was outstanding as of December 31, 2011.
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 on the Consolidated Balance Sheets is primarily due to equity contributions from owners of $27 million and the deconsolidation of Signal Peak for $45 million, partially offset by net losses attributable to noncontrolling interests of $16 million and an equity distribution to owners of $5 million during the year ended December 31, 2011.
In order to evaluate contracts for consolidation treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregated variable interests into the following categories based on similar risk characteristics and significance.
Mining Operations
In 2008, FEV entered into a joint venture in the Signal Peak mining and coal transportation operations near Roundup, Montana. FEV made equity investments totaling $133.5 million in exchange for a 50% economic interest in the joint venture. On October 18, 2011, a subsidiary of Gunvor Group, Ltd purchased a one-third interest in the Signal Peak joint venture in which FEV held a 50% interest. As part of the transaction, FirstEnergy received $257.5 million in proceeds and retained a 33-1/3% equity ownership in the joint venture. The sale resulted in a pre-tax gain of approximately $569 million ($370 million after-tax), which includes $378.6 million from the remeasurement of FEV's retained investment. The gain attributed to the retained investment remeasurement will be amortized as coal is extracted from the mine on a units of production method.
(In millions) 
Fair value of retained noncontrolling investment$400.0
Less: Carrying value of retained interest21.4
Gain on retained interest$378.6
FirstEnergy previously consolidated this joint venture and, as a result of the sale, its retained 33-1/3% interest is accounted for using the equity method of accounting.
Trusts
FirstEnergy’s consolidated financial statements include PNBV and Shippingport - those trusts are included in the consolidated financial statements of OE and CEI, respectively. OE used debt and available funds to purchase the notes issued by PNBV for the purchase of lease obligation bonds. Ownership of PNBV includes a 3% equity interest by an unaffiliated third party and a 3% equity interest held by OES Ventures, a wholly owned subsidiary of OE. CEI and TE used debt and available funds to purchase the notes issued by Shippingport.
PATH-WV
PATH, LLC was formed to construct, through its operating companies, the PATH Project, which is a high-voltage transmission line that was proposed to extend from West Virginia through Virginia and into Maryland, including modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland as directed by PJM. PATH, LLC is a series limited liability company that is comprised of multiple series, each of which has separate rights, powers and duties regarding specified property and the series profits and losses associated with such property. A subsidiary of AE owns 100% of the Allegheny Series and 50% of the West Virginia Series (PATH-WV), which is a joint venture with a subsidiary of AEP. FirstEnergy is not the primary beneficiary of PATH-WV, as it does not have control over the significant activities affecting the economics of the portion of the PATH Project to be constructed by PATH-WV.
Because of the nature of PATH-WV's operations and its FERC approved rate mechanism, FirstEnergy's maximum exposure to loss consists of its equity investment in PATH-WV, which was $29 million as of December 31, 2011.


214


Power Purchase Agreements
FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities may be VIEs to the extent that they own a plant that sells substantially all of its output to certain of the Utilities if the contract price for power is correlated with the plant's variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed, Penelec, PE, WP and MP, maintains 23 long-term power purchase agreements with NUG entities that were entered into pursuant to PURPA. 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 four of these NUG entities, it does not have a variable interest in the NUG entities or the NUG entities do not meet the criteria to be considered a VIE. JCP&L, PE and WP may hold variable interests in the remaining four entities; however, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities.
Because JCP&L, PE and WP have no equity or debt interests in the NUG entities, their maximum exposure to loss relates primarily to the above-market costs incurred for power. FirstEnergy expects any above-market costs incurred by its subsidiaries to be recovered from customers, except as described further below. Purchased power costs related to the four contracts that may contain a variable interest that were held by FirstEnergy subsidiaries during the year ended December 31, 2011 were $176 million, $101.6 million and $48.9 million for JCP&L, PE and WP, respectively. Purchased power costs related to the two contracts that may contain a variable interest that were held by JCP&L during the years ended December 31, 2010 and 2009 were $243 million and $225 million, respectively.
In 1998 the PPUC issued an order approving a transition plan for WP that disallowed certain costs, including an estimated amount for an adverse power purchase commitment related to the NUG entity for which WP may hold a variable interest. As of December 31, 2011, WP's reserve for this adverse purchase power commitment was $53 million, including a current liability of $11 million, and is being amortized over the life of the commitment.
Loss Contingencies
FirstEnergy has variable interests in certain sale-leaseback transactions. FirstEnergy is not the primary beneficiary of these interests as it does not have control over the significant activities affecting the economics of the 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 would render the applicable plant worthless. Net discounted lease payments would not be payable if the casualty loss payments were made. The following table discloses each company’s net exposure to loss based upon the casualty value provisions mentioned above as of December 31, 2011:
  
Maximum
Exposure
 
Discounted Lease
Payments, net(1)
 
Net
Exposure
  (In millions)
FES $1,362
 $1,159
 $203
OE 606
 416
 190
CEI(2)
 587
 71
 516
TE(2)
 587
 309
 278
(1)
The net present value of FirstEnergy’s sale and leaseback operating lease commitments is $1.6 billion.
(2)
CEI and TE are jointly and severally liable for the maximum loss amounts under certain sale-leaseback agreements.

See Note 6, Leases, for a discussion of CEI's and TE's assignment of their leasehold interest in the Bruce Mansfield Plant to FGCO.
9. FAIR VALUE OF FINANCIAL INSTRUMENTSMEASUREMENTS
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 considereddefined as short-term financial instruments under GAAP and are reported on the Consolidated Balance Sheets at cost, (whichwhich approximates their fair market value) undervalue, 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, excluding capital lease obligations and net unamortized premiums and discounts, as of December 31, 20092011 and 2008:2010:


  
December 31, 2009
  
December 31, 2008
 
  Carrying  Fair  Carrying  Fair 
  
Value
  
Value
  
Value
  
Value
 
  (In millions) 
FirstEnergy
 $13,753  $14,502  $11,585  $11,146 
FES
  4,224   4,306   2,552   2,528 
OE
  1,169   1,299   1,232   1,223 
CEI
  1,873   2,032   1,741   1,618 
TE
  600   638   300   244 
JCP&L
  1,840   1,950   1,569   1,520 
Met-Ed
  842   909   542   519 
Penelec
  1,144   1,177   779   721 
215


  December 31, 2011 December 31, 2010
  Carrying Value Fair Value Carrying Value Fair Value
  (In millions)
FirstEnergy(1)
 $17,165
 $19,320
 $13,928
 $14,845
FES 3,675
 3,931
 4,279
 4,403
OE 1,157
 1,434
 1,159
 1,321
CEI 1,831
 2,162
 1,853
 2,035
TE 600
 741
 600
 653
JCP&L 1,777
 2,080
 1,810
 1,962
Met-Ed 729
 824
 742
 821
Penelec 1,120
 1,251
 1,120
 1,189
(1)
Includes debt assumed in the AE merger (see Note 2, Merger) with a carrying value and a fair value as of December 31, 2011, of $4,355 million and $4,561 million, respectively.
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 FESFirstEnergy and the Utilities.its subsidiaries listed above.

(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.

199

FESFE and the Utilitiesits subsidiaries 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'ssecurity’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, FESFE and the Utilitiesits subsidiaries consider their intent to hold the security, the likelihood that they will be required to sell the security before recovery of their cost basis and the likelihood of recovery of the security'ssecurity’s entire amortized cost basis.

Unrealized gains applicable to the decommissioning trusts of FES, OE and TE are recognized in OCI because fluctuations in fair value will eventually impact earnings while unrealized losses are recorded to 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 because the difference between investments held in the trust and the decommissioning liabilities will be recovered from or refunded to customers.
The investment policy for the NDT funds restricts or limits the trusts’ 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 funds’ custodian or managers and their parents or subsidiaries.
Available-For-Sale Securities

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

The following table summarizes the amortized cost basis, unrealized gains and losses and fair values of investments held in available-for-sale securitiesNDT, nuclear fuel disposal trusts and NUG trusts as of December 31, 20092011 and 2008:2010:


216
  
December 31, 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)
 $1,727  $22  $-  $1,749  $1,078  $56  $-  $1,134 
FES
  1,043   3   -   1,046   401   28   -   429 
OE
  55   -   -   55   86   9   -   95 
TE
  72   -   -   72   66   8   -   74 
JCP&L
  271   9   -   280   249   9   -   258 
Met-Ed
  120   5   -   125   111   4   -   115 
Penelec
  166   5   -   171   164   3   -   167 
                                 
Equity securities
                                
FirstEnergy
 $252  $43  $-  $295  $589  $39  $-  $628 
FES
  -   -   -   -   355   25   -   380 
OE
  -   -   -   -   17   1   -   18 
JCP&L
  74   11   -   85   64   2   -   66 
Met-Ed
  117   23   -   140   101   9   -   110 
Penelec
  61   9   -   70   51   2   -   53 


  
December 31, 2011(1)
 
December 31, 2010(2)
  Cost Basis Unrealized Gains Unrealized Losses Fair Value Cost Basis Unrealized Gains Unrealized Losses Fair Value
  (In millions)
Debt securities                
FirstEnergy $1,980
 $25
 $—
 $2,005
 $1,699
 $31
 $—
 $1,730
FES 1,012
 13
 —
 1,025
 980
 13
 —
 993
OE 134
 —
 —
 134
 123
 1
 —
 124
TE 53
 1
 —
 54
 42
 —
 —
 42
JCP&L 356
 7
 —
 363
 281
 9
 —
 290
Met-Ed 232
 2
 —
 234
 127
 4
 —
 131
Penelec 193
 2
 —
 195
 145
 4
 —
 149
Equity securities                
FirstEnergy $222
 $36
 $—
 $258
 $268
 $69
 $—
 $337
FES 104
 20
 —
 124
 —
 —
 —
 —
TE 22
 5
 —
 27
 —
 —
 —
 —
JCP&L 27
 3
 —
 30
 80
 17
 —
 97
Met-Ed 46
 5
 —
 51
 125
 35
 —
 160
Penelec 23
 3
 —
 26
 63
 16
 —
 79
(1)Excludes cash balances of $137 million at FirstEnergy, $43 million at FES, $3 million at JCP&L, $66 million at OE, $23 million at Penelec and $2 million at TE.
(1)
Excludes short-term cash balances of $244investments: FirstEnergy — $164 million at FirstEnergy, $225; FES — $74 million at FES, $12; OE — $2 million at; TE — $2 million; JCP&L — $19 million; Met-Ed — $25 million and Penelec $4— $41 million at OE and $1 million at Met-Ed..
(3)Includes fair values as of December 31, 2009
(2)
Excludes short-term cash investments: FirstEnergy — $193 million; FES — $153 million; OE — $3 million; TE — $34 million; JCP&L — $3 million; Met-Ed — $(3) million and 2008 of $1,224Penelec — $4 million and $953 million of government obligations, $523 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 net of adjustments recorded to earnings and interest and dividend income for the three years ended December 31, 2011, 2010 and 2009 were as follows:
December 31, 2011 Sales Proceeds Realized Gains Realized Losses 
Interest and
Dividend Income
  (In millions)
FirstEnergy $4,207
 $229
 $(90) $82
FES 1,843
 80
 (46) 47
OE 154
 6
 —
 3
TE 120
 5
 (5) 2
JCP&L 779
 39
 (11) 15
Met-Ed 860
 64
 (16) 8
Penelec 451
 35
 (12) 6
December 31, 2010 Sales Proceeds Realized Gains Realized Losses Interest and Dividend Income
  (In millions)
FirstEnergy $3,172
 $126
 $(107) $79
FES 1,927
 92
 (75) 47
OE 83
 2
 —
 3
TE 126
 3
 (1) 2
JCP&L 411
 10
 (10) 14
Met-Ed 460
 13
 (14) 7
Penelec 165
 6
 (7) 6


  FirstEnergy  FES  OE  TE  JCP&L  Met-Ed  Penelec 
2009
 (In millions) 
Proceeds from sales
 $2,229  $1,379  $132  $169  $397  $68  $84 
Realized gains
  226   199   11   7   6   2   1 
Realized losses
  155   117   4   1   12   13   8 
Interest and dividend income
  60   27   4   2   14   7   6 
                             
2008
                            
Proceeds from sales
 $1,657  $951  $121  $38  $248  $181  $118 
Realized gains
  115   99   11   1   1   2   1 
Realized losses
  237   184   9   -   17   17   10 
Interest and dividend income
  76   37   5   3   14   9   8 
                             
2007
                            
Proceeds from sales
 $1,295  $656  $38  $45  $196  $185  $175 
Realized gains
  103   29   1   1   23   30   19 
Realized losses
  53   42   4   1   3   2   1 
Interest and dividend income
  80   42   4   3   13   8   10 
217


200
December 31, 2009 Sales Proceeds Realized Gains Realized Losses Interest and Dividend Income
  (In millions)
FirstEnergy $2,229
 $226
 $(155) $60
FES 1,379
 199
 (117) 27
OE 131
 11
 (4) 4
TE 169
 7
 (1) 2
JCP&L 397
 6
 (12) 14
Met-Ed 68
 2
 (13) 7
Penelec 84
 1
 (8) 6

Unrealized gains applicable to the decommissioning trusts of FES, OE and TE 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 2009, 2008 and 2007, FirstEnergy recognized $176 million, $63 million and $10 million of net realized gains resulting from the sale of securities held in nuclear decommissioning trusts.

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 (excludingas of December 31, 2011 and 2010:
  December 31, 2011 December 31, 2010
  Cost Basis Unrealized Gains Fair Value Cost Basis Unrealized Gains Fair Value
  (In millions)
Debt Securities            
FirstEnergy $402
 $50
 $452
 $476
 $91
 $567
OE 163
 21
 184
 190
 51
 241
CEI 287
 28
 315
 340
 41
 381
Investments in emission allowances, employee benefits,benefit trusts and cost and equity method investments totaling $693 million as of $264 million and $293 million that are not required to be disclosed) as December 31, 20092011, and 2008:
 December 31, 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
 $544  $72  $-  $616  $673  $14  $13  $674 
OE
  217   29   -   246   240   -   13   227 
CEI
  389   43   -   432   426   9   -   435 

$259 million as of December 31, 2010, are excluded from the amounts reported above.
Notes Receivable

The following table below provides the approximate fair value and related carrying amounts of notes receivable as of December 31, 20092011 and 2008:

 
December 31, 2009
 
December 31, 2008
 
 Carrying Fair Carrying Fair 
 
Value
 
Value
 
Value
 
Value
 
Notes receivable(In millions) 
FirstEnergy $36  $35  $45  $44 
FES  2   1   75   74 
OE  -   -   257   294 
TE
  124   141   180   189 

2010. The fair value of notes receivable represents the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms. The maturity dates rangedate of notes receivable due from 2010 to 2040.affiliated companies is 2016.

  December 31, 2011 December 31, 2010
  Carrying Value Fair Value Carrying Value Fair Value
  (In millions)
FirstEnergy $—
 $—
 $7
 $8
TE(1)
 81
 92
 104
 118
(C)
(1)
RECURRING FAIR VALUE MEASUREMENTSRepresents TE's investment in the Shippingport Trust notes (see Note 6, Leases), which is eliminated during consolidation.
RECURRING FAIR VALUE MEASUREMENTS

Fair value is the price that would be received for an asset or paid to transferAuthoritative accounting guidance establishes 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. TheThis hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (Level 1)Level 1 measurements and the lowest priority to unobservable inputs (Level 3).Level 3 measurements. The three levels of the fair value hierarchy are as follows:


Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those where transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. FirstEnergy’s Level 1 assets and liabilities primarily consist of exchange-traded derivatives and equity securities listed on active exchanges that are held in various trusts.218


201

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.

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 December 31, 2009 and 2008. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. FirstEnergy's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the fair valuation of assets and liabilities and their placement within the fair value hierarchy levels. During 2009, there were no significant transfers in or out of Level 1, Level 2, and Level 3.

Recurring Fair Value Measures as of December 31, 2009 
  Level 1 – Assets  Level 1 - Liabilities 
  (In millions) 
  Derivatives  
Available-for-Sale Securities(1)
  Other Investments  Total  Derivatives  
NUG Contracts(2)
  Total 
FirstEnergy $-  $294  $-  $294  $11  $-  $11 
FES  -   -   -   -   11   -   11 
OE  -   -   -   -   -   -   - 
JCP&L  -   87   -   87 �� -   -   - 
Met-Ed  -   133   -   133   -   -   - 
Penelec  -   74   -   74   -   -   - 
                             
  Level 2 - Assets  Level 2 - Liabilities 
  Derivatives  
Available-for-Sale Securities(1)
  Other Investments  Total  Derivatives  
NUG Contracts(2)
  Total 
FirstEnergy $34  $1,864  $11  $1,909  $224  $-  $224 
FES  15   1,072   -   1,087   224   -   224 
OE  -   120   -   120   -   -   - 
TE  -   72   -   72   -   -   - 
JCP&L  5   280   -   285   -   -   - 
Met-Ed  9   134   -   143   -   -   - 
Penelec  5   186   -   191   -   -   - 
                             
  Level 3 - Assets  Level 3 - Liabilities 
  Derivatives  
Available-for-Sale Securities(1)
  
NUG Contracts(2)
  Total  Derivatives  
NUG Contracts(2)
  Total 
FirstEnergy $-  $-  $200  $200  $-  $643  $643 
JCP&L  -   -   9   9   -   399   399 
Met-Ed  -   -   176   176   -   143   143 
Penelec  -   -   15   15   -   101   101 
(1)Consists of investments in nuclear decommissioning trusts, spent nuclear fuel trusts and NUG trusts. Excludes $21 million of receivables, payables and accrued income.
(2)NUG contracts are subject to regulatory accounting and do not impact earnings.
202

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. Excludes $5 million of receivables, payables and accrued income.
(2)Level 1NUG contracts– Quoted prices for identical instruments in active markets.
Level 2– Quoted prices for similar instruments in active markets;
– quoted prices for identical or similar instruments in markets that are subjectnot active and
– model-derived valuations for which all significant inputs are observable market data.
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.
Level 3– Valuation inputs are unobservable and significant to regulatory accountingthe fair value measurement.
FirstEnergy develops its view of the future market price through a combination of market observation and do not impact earnings.assessment (generally for the short term) and fundamental modeling (generally for the long term). 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 determination of the above fair value measures takes into consideration various factors. These factors include, but are not limited to, nonperformance risk, including counterparty credit risk and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of nonperformancethese forms of risk was immaterialwere not significant in the fair value measurements.

The following tables set forth financial assets and liabilities that are accounted for at fair value by level within the fair value hierarchy. There were no significant transfers between levels during 2011 and 2010.
FIRSTENERGY
  December 31, 2011 December 31, 2010
  Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets (In millions)
Corporate debt securities $—
 $1,544
 $—
 $1,544
 $—
 $597
 $—
 $597
Derivative assets — commodity contracts —
 264
 —
 264
 —
 250
 —
 250
Derivative assets — FTRs —
 —
 1
 1
 —
 —
 —
 —
Derivative assets — NUG contracts(1)
 —
 —
 56
 56
 —
 —
 122
 122
Equity securities(2)
 259
 —
 —
 259
 338
 —
 —
 338
Foreign government debt securities —
 3
 —
 3
 —
 149
 —
 149
U.S. government debt securities —
 148
 —
 148
 —
 595
 —
 595
U.S. state debt securities —
 314
 —
 314
 —
 379
 —
 379
Other(3)
 —
 225
 —
 225
 —
 219
 —
 219
Total assets $259
 $2,498
 $57
 $2,814
 $338
 $2,189
 $122
 $2,649
Liabilities                
Derivative liabilities — commodity contracts $—
 $(247) $—
 $(247) $—
 $(348) $—
 $(348)
Derivative liabilities — FTRs —
 —
 (23) (23) —
 —
 —
 —
Derivative liabilities — NUG contracts(1)
 —
 —
 (349) (349) —
 —
 (466) (466)
Total liabilities $—
 $(247) $(372) $(619) $—
 $(348) $(466) $(814)
Net assets (liabilities)(4)
 $259
 $2,251
 $(315) $2,195
 $338
 $1,841
 $(344) $1,835
(1)
NUG contracts are generally subject to regulatory accounting and do not impact earnings.
(2)
NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index.
(3)
Primarily consists of short-term cash investments.
(4)
Excludes $(52) million and $(7) million as of December 31, 2011 and 2010, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.


219


Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the fair value of NUG contracts held by the Utilities and FTRs held by FirstEnergy and classified as Level 3 in the fair value hierarchy for 2009the years ending December 31, 2011 and 2008 (in millions)2010:

  FirstEnergy  JCP&L  Met-Ed  Penelec 
Balance as of January 1, 2009 $(332) $(518) $150  $36 
Settlements(1)
  358   168   88   102 
Purchases  -   -   -   - 
Issuances  -   -   -   - 
Sales  -   -   -   - 
Unrealized losses(1)
  (470)  (41)  (205)  (224)
Net transfers to Level 3  -   -   -   - 
Net transfers from Level 3  -   -   -   - 
Balance as of December 31, 2009 $(444) $(391) $33  $(86)
                 
                 
Balance as of January 1, 2008 $(803) $(750) $(28) $(25)
Settlements(1)
  278   232   34   12 
Unrealized gains(1)
  193   -   144   49 
Net transfers to (from) Level 3  -   -   -   - 
Balance as of December 31, 2008 $(332) $(518) $150  $36 
                 
  
Derivative Assets(1)
 
Derivative Liabilities(1)
 
Net(1)
  (In millions)
December 31, 2009 Balance $200
 $(643) $(443)
Realized gain (loss) —
 —
 —
Unrealized gain (loss) (71) (110) (181)
Purchases —
 —
 —
Issuances —
 —
 —
Sales —
 —
 —
Settlements (7) 287
 280
Transfers in (out) of Level 3 —
 —
 —
December 31, 2010 Balance $122
 $(466) $(344)
Realized gain (loss) —
 —
 —
Unrealized gain (loss) (55) (173) (228)
Purchases 13
 (4) 9
Issuances —
 —
 —
Sales —
 —
 —
Settlements (23) 283
 260
Transfers in (out) of Level 3 —
 (12) (12)
December 31, 2011 Balance $57
 $(372) $(315)
(1)
Changes in the fair value of NUG contracts are generally subject to regulatory accounting and do not impact earnings.
FES
  December 31, 2011 December 31, 2010
  Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets (In millions)
Corporate debt securities $—
 $1,010
 $—
 $1,010
 $—
 $528
 $—
 $528
Derivative assets — commodity contracts —
 248
 —
 248
 —
 241
 —
 241
Derivative assets — FTRs —
 —
 1
 1
 —
 —
 —
 —
Equity securities(1)
 124
 —
 —
 124
 —
 —
 —
 —
Foreign government debt securities —
 3
 —
 3
 —
 147
 —
 147
U.S. government debt securities —
 7
 —
 7
 —
 308
 —
 308
U.S. state debt securities —
 5
 —
 5
 —
 6
 —
 6
Other(2)
 —
 132
 —
 132
 —
 148
 —
 148
Total assets $124
 $1,405
 $1
 $1,530
 $—
 $1,378
 $—
 $1,378
Liabilities                
Derivative liabilities — commodity contracts $—
 $(234) $—
 $(234) $—
 $(348) $—
 $(348)
Derivative liabilities — FTRs —
 —
 (7) (7) —
 —
 —
 —
Total liabilities $—
 $(234) $(7) $(241) $—
 $(348) $—
 $(348)
Net assets (liabilities)(3)
 $124
 $1,171
 $(6) $1,289
 $—
 $1,030
 $—
 $1,030
(1)
NDT funds hold equity portfolios whose performance of which is benchmarked against the Alerian MLP Index.
(2)
Primarily consists of short-term cash investments.
(3)
Excludes $(58) million and $7 million as of December 31, 2011 and 2010, respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.


220


Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the fair value of FTRs held by FES and classified as Level 3 in the fair value hierarchy for the years ending December 31, 2011 and 2010:
  Derivative Asset FTRs Derivative Liability FTRs Net FTRs
  (In millions)
December 31, 2010 Balance $—
 $—
 $—
Realized gain (loss) —
 —
 —
Unrealized gain (loss) 4
 (8) (4)
Purchases 2
 (1) 1
Issuances —
 —
 —
Sales —
 —
 —
Settlements (5) 2
 (3)
Transfers in (out) of Level 3 —
 —
 —
December 31, 2011 Balance $1
 $(7) $(6)
OE
  December 31, 2011 December 31, 2010
  Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets (In millions)
Corporate debt securities $—
 $3
 $—
 $3
 $—
 $—
 $—
 $—
U.S. government debt securities —
 132
 —
 132
 —
 124
 —
 124
Other(1)
 —
 2
 —
 2
 —
 2
 —
 2
Total assets(2)
 $—
 $137
 $—
 $137
 $—
 $126
 $—
 $126
(1)
Primarily consists of short-term cash investments.
(2)
Excludes $1 million as of December 31, 2011 and 2010 of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.
TE
  December 31, 2011 December 31, 2010
  Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets (In millions)
Corporate debt securities $—
 $53
 $—
 $53
 $—
 $7
 $—
 $7
Equity securities(1)
 27
 —
 —
 27
 —
 —
 —
 —
U.S. government debt securities —
 —
 —
 —
 —
 33
 —
 33
U.S. state debt securities —
 —
 —
 —
 —
 1
 —
 1
Other(2)
 —
 3
 —
 3
 —
 35
 —
 35
Total assets $27
 $56
 $—
 $83
 $—
 $76
 $—
 $76
(1)
NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index.
(2)
Primarily consists of short-term cash investments.


221


JCP&L
  December 31, 2011 December 31, 2010
  Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets (In millions)
Corporate debt securities $—
 $144
 $—
 $144
 $—
 $23
 $—
 $23
Derivative assets — commodity contracts —
 —
 —
 —
 —
 2
 —
 2
Derivative assets — NUG contracts(1)
 —
 —
 4
 4
 —
 —
 6
 6
Equity securities(2)
 30
 —
 —
 30
 96
 —
 —
 96
U.S. government debt securities —
 2
 —
 2
 —
 33
 —
 33
U.S. state debt securities —
 219
 —
 219
 —
 236
 —
 236
Other(3)
 —
 15
 —
 15
 —
 4
 —
 4
Total assets $30
 $380
 $4
 $414
 $96
 $298
 $6
 $400
Liabilities                
Derivative liabilities — NUG contracts(1)
 $—
 $—
 $(147) $(147) $—
 $—
 $(233) $(233)
Total liabilities $—
 $—
 $(147) $(147) $—
 $—
 $(233) $(233)
Net assets (liabilities)(4)
 $30
 $380
 $(143) $267
 $96
 $298
 $(227) $167
(1)
NUG contracts are subject to regulatory accounting and do not impact earnings.
(2)
NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index.
(3)
Primarily consists of short-term cash investments.
(4)
Excludes $2 million and $(3) million as of December 31, 2011 and December 31, 2010 of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.
Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the fair value of NUG contracts held by JCP&L and classified as Level 3 in the fair value hierarchy for the years ending December 31, 2011 and 2010:
  
Derivative Asset NUG Contracts(1)
 
Derivative Liability NUG Contracts(1)
 
Net NUG Contracts(1)
  (In millions)
December 31, 2009 Balance $8
 $(399) $(391)
Realized gain (loss) —
 —
 —
Unrealized gain (loss) (1) 36
 35
Purchases —
 —
 —
Issuances —
 —
 —
Sales —
 —
 —
Settlements (1) 130
 129
Transfers in (out) of Level 3 —
 —
 —
December 31, 2010 Balance $6
 $(233) $(227)
Realized gain (loss) —
 —
 —
Unrealized gain (loss) (2) (11) (13)
Purchases —
 —
 —
Issuances —
 —
 —
Sales —
 —
 —
Settlements —
 97
 97
Transfers in (out) of Level 3 —
 —
 —
December 31, 2011 Balance $4
 $(147) $(143)
(1)
Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings.


222


MET-ED
  December 31, 2011 December 31, 2010
  Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets (In millions)
Corporate debt securities $—
 $229
 $—
 $229
 $—
 $32
 $—
 $32
Derivative assets — commodity contracts —
 —
 —
 —
 —
 5
 —
 5
Derivative assets — NUG contracts(1)
 —
 —
 49
 49
 —
 —
 112
 112
Equity securities(2)
 51
 —
 —
 51
 160
 —
 —
 160
Foreign government debt securities —
 —
 —
 —
 —
 1
 —
 1
U.S. government debt securities —
 5
 —
 5
 —
 88
 —
 88
U.S. state debt securities —
 —
 —
 —
 —
 2
 —
 2
Other(3)
 —
 23
 —
 23
 —
 14
 —
 14
Total assets $51
 $257
 $49
 $357
 $160
 $142
 $112
 $414
Liabilities                
Derivative liabilities — NUG contracts(1)
 $—
 $—
 $(79) $(79) $—
 $—
 $(116) $(116)
Total liabilities $—
 $—
 $(79) $(79) $—
 $—
 $(116) $(116)
Net assets (liabilities)(4)
 $51
 $257
 $(30) $278
 $160
 $142
 $(4) $298
(1)
NUG contracts are subject to regulatory accounting and do not impact earnings.
(2)
NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index.
(3)
Primarily consists of short-term cash investments.
(4)
Excludes $2 million and $(9) million as of December 31, 2011 and 2010, respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.
Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the fair value of NUG contracts held by Met-Ed and classified as Level 3 in the fair value hierarchy for the years ending December 31, 2011 and 2010:
  
Derivative Asset NUG Contracts(1)
 
Derivative Liability NUG Contracts(1)
 
Net
NUG Contracts(1)
  (In millions)
December 31, 2009 Balance $176
 $(143) $33
Realized gain (loss) —
 —
 —
Unrealized gain (loss) (59) (38) (97)
Purchases —
 —
 —
Issuances —
 —
 —
Sales —
 —
 —
Settlements (5) 65
 60
Transfers in (out) of Level 3 —
 —
 —
December 31, 2010 Balance $112
 $(116) $(4)
Realized gain (loss) —
 —
 —
Unrealized gain (loss) (57) (31) (88)
Purchases —
 —
 —
Issuances —
 —
 —
Sales —
 —
 —
Settlements (6) 68
 62
Transfers in (out) of Level 3 —
 —
 —
December 31, 2011 Balance $49
 $(79) $(30)
(1)
Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings.
 


223


PENELEC
203
  December 31, 2011 December 31, 2010
  Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets (In millions)
Corporate debt securities $—
 $104
 $—
 $104
 $—
 $8
 $—
 $8
Derivative assets — commodity contracts —
 —
 —
 —
 —
 2
 —
 2
Derivative assets — NUG contracts(1)
 —
 —
 3
 3
 —
 —
 4
 4
Equity securities(2)
 26
 —
 —
 26
 81
 —
 —
 81
U.S. government debt securities —
 2
 —
 2
 —
 9
 —
 9
U.S. state debt securities —
 90
 —
 90
 —
 133
 —
 133
Other(3)
 —
 39
 —
 39
 —
 5
 —
 5
Total assets $26
 $235
 $3
 $264
 $81
 $157
 $4
 $242
Liabilities                
Derivative liabilities — NUG contracts(1)
 $—
 $—
 $(123) $(123) $—
 $—
 $(117) $(117)
Total liabilities $—
 $—
 $(123) $(123) $—
 $—
 $(117) $(117)
Net assets (liabilities)(4)
 $26
 $235
 $(120) $141
 $81
 $157
 $(113) $125
(1)
NUG contracts are subject to regulatory accounting and do not impact earnings.
(2)
NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index.
(3)
Primarily consists of short-term cash investments.
(4)
Excludes $1 million and $(3) million as of December 31, 2011 and 2010, respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.
Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the fair value of NUG contracts held by Penelec and classified as Level 3 in the fair value hierarchy for the years ending December 31, 2011 and 2010:
  
Derivative Asset NUG Contracts(1)
 
Derivative Liability NUG Contracts(1)
 
Net
NUG Contracts(1)
  (In millions)
December 31, 2009 Balance $16
 $(101) $(85)
Realized gain (loss) —
 —
 —
Unrealized gain (loss) (11) (108) (119)
Purchases —
 —
 —
Issuances —
 —
 —
Sales —
 —
 —
Settlements (1) 92
 91
Transfers in (out) of Level 3 —
 —
 —
December 31, 2010 Balance $4
 $(117) $(113)
Realized gain (loss) —
 —
 —
Unrealized gain (loss) —
 (103) (103)
Purchases —
 —
 —
Issuances —
 —
 —
Sales —
 —
 —
Settlements (1) 97
 96
Transfers in (out) of Level 3 —
 —
 —
December 31, 2011 Balance $3
 $(123) $(120)
(1)
Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings.
6.During 2011, FirstEnergy received approximately $130 million from assigning a substantially below-market, long-term fossil fuel contract to a third party. As a result, FirstEnergy entered into a new long-term contract with another supplier for replacement fuel based on current market prices. The new contract runs for nine years, which is the remaining term of the assigned contract. The transaction reduced fuel costs during the year by approximately $123 million.
10. DERIVATIVE INSTRUMENTS


224


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 Risk Policy 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.practice. FirstEnergy also uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.

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 under the accrual method of accounting. The changesaccounting, and their effects are included in earnings at the time of contract performance. Changes in the fair value of derivative instruments that do not meetqualified and were designated as cash flow hedge instruments are recorded in AOCI. Changes in the normal purchase 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 thefair value of the hedged item. 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 wouldthat are not have had a material effect on FirstEnergy’s consolidated financial position (assets, liabilities and equity) ordesignated as cash flows as of December 31, 2009. Based on derivative contracts held as of December 31, 2009, an adverse 10% changeflow hedge instruments are recorded in commodity prices would decrease net income by approximately $9 million during the next 12 months.

Interest Rate Risk

on a mark-to-market basis. FirstEnergy uses a combination of fixed-rate and variable-rate debt to manage interest rate exposure. Fixed-to-floating interest rate swaps are used, which are typically designated as fair value hedges, as a means to manage interest rate exposure. In addition, FirstEnergy uses interest rate derivatives to lock in interest rate levels in anticipation of future financings, which are typically designated as cash-flow hedges.has contractual derivative agreements through December 2018.

Cash Flow HedgesMining Operations

In 2008, FEV entered into a joint venture in the Signal Peak mining and coal transportation operations near Roundup, Montana. FEV made equity investments totaling $133.5 million in exchange for a 50% economic interest in the joint venture. On October 18, 2011, a subsidiary of Gunvor Group, Ltd purchased a one-third interest in the Signal Peak joint venture in which FEV held a 50% interest. As part of the transaction, FirstEnergy received $257.5 million in proceeds and retained a 33-1/3% equity ownership in the joint venture. The sale resulted in a pre-tax gain of approximately $569 million ($370 million after-tax), which includes $378.6 million from the remeasurement of FEV's retained investment. The gain attributed to the retained investment remeasurement will be amortized as coal is extracted from the mine on a units of production method.
Under
(In millions) 
Fair value of retained noncontrolling investment$400.0
Less: Carrying value of retained interest21.4
Gain on retained interest$378.6
FirstEnergy previously consolidated this joint venture and, as a result of the revolving credit facility (see Note 14), FirstEnergy andsale, its subsidiaries, incur variableretained 33-1/3% interest charges based on LIBOR. FirstEnergy currently holds a swap with a notional value of $100 million to hedge against changes in associated interest rates. This hedge will expire in January 2010 and is accounted for using the equity method of accounting.
Trusts
FirstEnergy’s consolidated financial statements include PNBV and Shippingport - those trusts are included in the consolidated financial statements of OE and CEI, respectively. OE used debt and available funds to purchase the notes issued by PNBV for the purchase of lease obligation bonds. Ownership of PNBV includes a 3% equity interest by an unaffiliated third party and a 3% equity interest held by OES Ventures, a wholly owned subsidiary of OE. CEI and TE used debt and available funds to purchase the notes issued by Shippingport.
PATH-WV
PATH, LLC was formed to construct, through its operating companies, the PATH Project, which is a high-voltage transmission line that was proposed to extend from West Virginia through Virginia and into Maryland, including modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland as directed by PJM. PATH, LLC is a cash flow hedge. Asseries limited liability company that is comprised of December 31, 2009,multiple series, each of which has separate rights, powers and duties regarding specified property and the fair valueseries profits and losses associated with such property. A subsidiary of AE owns 100% of the outstanding swap was immaterial.

Allegheny Series and 50% of the West Virginia Series (PATH-WV), which is a joint venture with a subsidiary of AEP. FirstEnergy uses forward starting swap agreements to hedge ais not the primary beneficiary of PATH-WV, as it does not have control over the significant activities affecting the economics of the portion of the consolidated interestPATH Project to be constructed by PATH-WV.
Because of the nature of PATH-WV's operations and its FERC approved rate risk associated with issuances of fixed-rate, long-term debt securitiesmechanism, FirstEnergy's maximum exposure to loss consists of its subsidiaries. These derivatives are treatedequity investment in PATH-WV, which was $29 million as cash flow hedges, protecting againstof December 31, 2011.


214


Power Purchase Agreements
FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities may be VIEs to the riskextent that they own a plant that sells substantially all of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the dateits output to certain of the Utilities if the contract price for power is correlated with the plant's variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed, Penelec, PE, WP and MP, maintains 23 long-term power purchase agreements with NUG entities that were entered into pursuant to PURPA. FirstEnergy was not involved in the creation of, and has no equity or debt issuance. During 2009, invested in, these entities.
FirstEnergy terminated forward swaps withhas determined that, for all but four of these NUG entities, it does not have a notional valuevariable interest in the NUG entities or the NUG entities do not meet the criteria to be considered a VIE. JCP&L, PE and WP may hold variable interests in the remaining four entities; however, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities.
Because JCP&L, PE and WP have no equity or debt interests in the NUG entities, their maximum exposure to loss relates primarily to the above-market costs incurred for power. FirstEnergy expects any above-market costs incurred by its subsidiaries to be recovered from customers, except as described further below. Purchased power costs related to the four contracts that may contain a variable interest that were held by FirstEnergy subsidiaries during the year ended December 31, 2011 were $176 million, $101.6 million and $48.9 million for JCP&L, PE and WP, respectively. Purchased power costs related to the two contracts that may contain a variable interest that were held by JCP&L during the years ended December 31, 2010 and 2009 were $243 million and $225 million, respectively.
In 1998 the PPUC issued an order approving a transition plan for WP that disallowed certain costs, including an estimated amount for an adverse power purchase commitment related to the NUG entity for which WP may hold a variable interest. As of $2.8 billionDecember 31, 2011, WP's reserve for this adverse purchase power commitment was $53 million, including a current liability of $11 million, and recognized losses of approximately $18.5 million; the ineffective portion recognized as an adjustment to interest expense was immaterial. The remaining effective portions will beis being amortized to interest expense over the life of the hedged debt.commitment.
Loss Contingencies
FirstEnergy has variable interests in certain sale-leaseback transactions. FirstEnergy is not the primary beneficiary of these interests as it does not have control over the significant activities affecting the economics of the 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 would render the applicable plant worthless. Net discounted lease payments would not be payable if the casualty loss payments were made. The following table discloses each company’s net exposure to loss based upon the casualty value provisions mentioned above as of December 31, 2011:
  
Maximum
Exposure
 
Discounted Lease
Payments, net(1)
 
Net
Exposure
  (In millions)
FES $1,362
 $1,159
 $203
OE 606
 416
 190
CEI(2)
 587
 71
 516
TE(2)
 587
 309
 278
(1)
The net present value of FirstEnergy’s sale and leaseback operating lease commitments is $1.6 billion.
(2)
CEI and TE are jointly and severally liable for the maximum loss amounts under certain sale-leaseback agreements.

Interest rate derivativesSee Note 6, Leases, for a discussion of CEI's and TE's assignment of their leasehold interest in the Bruce Mansfield Plant to FGCO.
9. FAIR VALUE MEASUREMENTS
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS
All borrowings with initial maturities of less than one year are included in "Other Noncurrent Liabilities" on FirstEnergy’s Consolidated Balance Sheets. The effects of interest rate derivativesdefined as short-term financial instruments under GAAP and are reported on the Consolidated StatementsBalance Sheets at cost, which approximates their fair market value, in the caption “Short-term borrowings.” The following table provides the approximate fair value and related carrying amounts of Incomelong-term debt and Comprehensive Income during 2009other long-term obligations, excluding capital lease obligations and 2008 were:net unamortized premiums and discounts, as of December 31, 2011 and 2010:


 December 31 
 2009 2008 
 (In millions) 
Effective Portion      
Loss Recognized in AOCL $(18) $(44)
Loss Reclassified from AOCL into Interest Expense  (40)  (15)
Ineffective Portion        
Loss Recognized in Interest Expense  -   (7)
215


  December 31, 2011 December 31, 2010
  Carrying Value Fair Value Carrying Value Fair Value
  (In millions)
FirstEnergy(1)
 $17,165
 $19,320
 $13,928
 $14,845
FES 3,675
 3,931
 4,279
 4,403
OE 1,157
 1,434
 1,159
 1,321
CEI 1,831
 2,162
 1,853
 2,035
TE 600
 741
 600
 653
JCP&L 1,777
 2,080
 1,810
 1,962
Met-Ed 729
 824
 742
 821
Penelec 1,120
 1,251
 1,120
 1,189
(1)
Includes debt assumed in the AE merger (see Note 2, Merger) with a carrying value and a fair value as of December 31, 2011, of $4,355 million and $4,561 million, respectively.
204The 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 FirstEnergy and its subsidiaries listed above.
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.
FE and its subsidiaries 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, FE and its subsidiaries consider their intent to hold the security, the likelihood that they will be required to sell the security before recovery of their cost basis and the likelihood of recovery of the security’s entire amortized cost basis.
Unrealized gains applicable to the decommissioning trusts of FES, OE and TE are recognized in OCI because fluctuations in fair value will eventually impact earnings while unrealized losses are recorded to 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 because the difference between investments held in the trust and the decommissioning liabilities will be recovered from or refunded to customers.
The investment policy for the NDT funds restricts or limits the trusts’ 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 funds’ custodian or managers and their parents or subsidiaries.
Available-For-Sale Securities
FES and the Utility Registrants hold debt and equity securities within their NDT, nuclear fuel disposal trusts and NUG trusts. These trust investments are considered available-for-sale securities at fair market value. FES and the Utility Registrants have no securities held for trading purposes.
The following table summarizes the amortized cost basis, unrealized gains and losses and fair values of investments held in NDT, nuclear fuel disposal trusts and NUG trusts as of December 31, 2011 and 2010:


216


  
December 31, 2011(1)
 
December 31, 2010(2)
  Cost Basis Unrealized Gains Unrealized Losses Fair Value Cost Basis Unrealized Gains Unrealized Losses Fair Value
  (In millions)
Debt securities                
FirstEnergy $1,980
 $25
 $—
 $2,005
 $1,699
 $31
 $—
 $1,730
FES 1,012
 13
 —
 1,025
 980
 13
 —
 993
OE 134
 —
 —
 134
 123
 1
 —
 124
TE 53
 1
 —
 54
 42
 —
 —
 42
JCP&L 356
 7
 —
 363
 281
 9
 —
 290
Met-Ed 232
 2
 —
 234
 127
 4
 —
 131
Penelec 193
 2
 —
 195
 145
 4
 —
 149
Equity securities                
FirstEnergy $222
 $36
 $—
 $258
 $268
 $69
 $—
 $337
FES 104
 20
 —
 124
 —
 —
 —
 —
TE 22
 5
 —
 27
 —
 —
 —
 —
JCP&L 27
 3
 —
 30
 80
 17
 —
 97
Met-Ed 46
 5
 —
 51
 125
 35
 —
 160
Penelec 23
 3
 —
 26
 63
 16
 —
 79
(1)
Excludes short-term cash investments: FirstEnergy — $164 million; FES — $74 million; OE — $2 million; TE — $2 million; JCP&L — $19 million; Met-Ed — $25 million and Penelec — $41 million.
(2)
Excludes short-term cash investments: FirstEnergy — $193 million; FES — $153 million; OE — $3 million; TE — $34 million; JCP&L — $3 million; Met-Ed — $(3) million and Penelec — $4 million.
Total unamortizedProceeds from the sale of investments in available-for-sale securities, realized gains and losses included in AOCL associated with prior interest rate hedges totaled $104 million ($62 millionon those sales net of tax)adjustments recorded to earnings and interest and dividend income for the three years ended December 31, 2011, 2010 and 2009 were as follows:
December 31, 2011 Sales Proceeds Realized Gains Realized Losses 
Interest and
Dividend Income
  (In millions)
FirstEnergy $4,207
 $229
 $(90) $82
FES 1,843
 80
 (46) 47
OE 154
 6
 —
 3
TE 120
 5
 (5) 2
JCP&L 779
 39
 (11) 15
Met-Ed 860
 64
 (16) 8
Penelec 451
 35
 (12) 6
December 31, 2010 Sales Proceeds Realized Gains Realized Losses Interest and Dividend Income
  (In millions)
FirstEnergy $3,172
 $126
 $(107) $79
FES 1,927
 92
 (75) 47
OE 83
 2
 —
 3
TE 126
 3
 (1) 2
JCP&L 411
 10
 (10) 14
Met-Ed 460
 13
 (14) 7
Penelec 165
 6
 (7) 6


217


December 31, 2009 Sales Proceeds Realized Gains Realized Losses Interest and Dividend Income
  (In millions)
FirstEnergy $2,229
 $226
 $(155) $60
FES 1,379
 199
 (117) 27
OE 131
 11
 (4) 4
TE 169
 7
 (1) 2
JCP&L 397
 6
 (12) 14
Met-Ed 68
 2
 (13) 7
Penelec 84
 1
 (8) 6
Held-To-Maturity Securities
The following table provides the amortized cost basis, unrealized gains and approximate fair values of investments in held-to-maturity securities as of December 31, 2009. Based2011 and 2010:
  December 31, 2011 December 31, 2010
  Cost Basis Unrealized Gains Fair Value Cost Basis Unrealized Gains Fair Value
  (In millions)
Debt Securities            
FirstEnergy $402
 $50
 $452
 $476
 $91
 $567
OE 163
 21
 184
 190
 51
 241
CEI 287
 28
 315
 340
 41
 381
Investments in emission allowances, employee benefit trusts and cost and equity method investments totaling $693 million as of December 31, 2011, and $259 million as of December 31, 2010, are excluded from the amounts reported above.
Notes Receivable
The table below provides the approximate fair value and related carrying amounts of notes receivable as of December 31, 2011 and 2010. The fair value of notes receivable represents the present value of the cash inflows based on current estimates, approximately $11 million will be amortizedthe yield to interest expensematurity. The yields assumed were based on financial instruments with similar characteristics and terms. The maturity date of notes receivable due from affiliated companies is 2016.
  December 31, 2011 December 31, 2010
  Carrying Value Fair Value Carrying Value Fair Value
  (In millions)
FirstEnergy $—
 $—
 $7
 $8
TE(1)
 81
 92
 104
 118
(1)
Represents TE's investment in the Shippingport Trust notes (see Note 6, Leases), which is eliminated during consolidation.
RECURRING FAIR VALUE MEASUREMENTS
Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the next twelve months. FirstEnergy’s interest rate swaps doinputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. The three levels of the fair value hierarchy are as follows:


218


Level 1– Quoted prices for identical instruments in active markets.
Level 2– Quoted prices for similar instruments in active markets;
– quoted prices for identical or similar instruments in markets that are not active and
– model-derived valuations for which all significant inputs are observable market data.
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.
Level 3– Valuation inputs are unobservable and significant to the fair value measurement.
FirstEnergy develops its view of the future market price through a combination of market observation and assessment (generally for the short term) and fundamental modeling (generally for the long term). 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 determination of the fair value measures takes into consideration various factors. These factors include, but are not include any contingentlimited to, nonperformance risk, including counterparty credit risk related features.and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of these forms of risk were not significant in the fair value measurements.
The following tables set forth financial assets and liabilities that are accounted for at fair value by level within the fair value hierarchy. There were no significant transfers between levels during 2011 and 2010.
FIRSTENERGY
  December 31, 2011 December 31, 2010
  Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets (In millions)
Corporate debt securities $—
 $1,544
 $—
 $1,544
 $—
 $597
 $—
 $597
Derivative assets — commodity contracts —
 264
 —
 264
 —
 250
 —
 250
Derivative assets — FTRs —
 —
 1
 1
 —
 —
 —
 —
Derivative assets — NUG contracts(1)
 —
 —
 56
 56
 —
 —
 122
 122
Equity securities(2)
 259
 —
 —
 259
 338
 —
 —
 338
Foreign government debt securities —
 3
 —
 3
 —
 149
 —
 149
U.S. government debt securities —
 148
 —
 148
 —
 595
 —
 595
U.S. state debt securities —
 314
 —
 314
 —
 379
 —
 379
Other(3)
 —
 225
 —
 225
 —
 219
 —
 219
Total assets $259
 $2,498
 $57
 $2,814
 $338
 $2,189
 $122
 $2,649
Liabilities                
Derivative liabilities — commodity contracts $—
 $(247) $—
 $(247) $—
 $(348) $—
 $(348)
Derivative liabilities — FTRs —
 —
 (23) (23) —
 —
 —
 —
Derivative liabilities — NUG contracts(1)
 —
 —
 (349) (349) —
 —
 (466) (466)
Total liabilities $—
 $(247) $(372) $(619) $—
 $(348) $(466) $(814)
Net assets (liabilities)(4)
 $259
 $2,251
 $(315) $2,195
 $338
 $1,841
 $(344) $1,835
(1)
NUG contracts are generally subject to regulatory accounting and do not impact earnings.
(2)
NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index.
(3)
Primarily consists of short-term cash investments.
(4)
Excludes $(52) million and $(7) million as of December 31, 2011 and 2010, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.


Fair Value Hedges219


FirstEnergy uses fixed-for-floating interest rate swap agreements to hedgeRollforward of Level 3 Measurements
The following table provides 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 riskreconciliation of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest ratesNUG contracts held by the Utilities and interest payment dates match those of the underlying obligations. As of December 31, 2009, the debt underlying the $250 million outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 6.45%, which the swaps have converted to a current weighted average variable rate of 5.4%. The gain or loss on the derivativeFTRs held by FirstEnergy and classified as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognizedLevel 3 in earnings and were immaterial in 2009.

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 where 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 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.

FirstEnergy discontinues hedge accounting prospectively when it is determined that a derivative is no longer effective in offsetting changes in the cash flows of a hedged item, in the case of forward-starting hedges, or when it is no longer probable that the forecasted transaction will occur. In 2009, FirstEnergy did not discontinue hedge accounting for any cash flow hedge items.

During 2008, in anticipation of certain regulatory actions, FES entered into purchased power contracts representing approximately 4.4 million MWH per year for MISO delivery in 2010 and 2011. These contracts, which represented less than 10% of FES's estimated Ohio load, were intended to cover potential short positions that were anticipated in those years and qualified for the normal purchase normal sale scope exception under accounting for Derivatives and Hedging. In the fourth quarter of 2009, as FES determined that the short positions in 2010 and 2011 were not expected to materialize based on reductions in PLR obligations and decreased demand due to economic conditions, the contracts were modified to financially settle to avoid congestion and transmission expenses associated with physical delivery. As a result of the modification, the fair value of the contracts was recorded, resulting in a mark-to-market charge of approximately $205 million ($129 million, after tax) to purchased power expense. For all other purchased power contracts qualifyinghierarchy for the normal purchase normal sale scope exception, the Company expects to take physical delivery of the power over the remaining term of the contracts.

205

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

Derivative Assets Derivative Liabilities 
  Fair Value   Fair Value 
  December 31  December 31   December 31  December 31 
  2009  2008   2009  2008 
Cash Flow Hedges (In millions) Cash Flow Hedges (In millions) 
Electricity Forwards      Electricity Forwards      
Current Assets $3  $11 Current Liabilities $7  $27 
Noncurrent Assets  11   - Noncurrent Assets  12   - 
Natural Gas Futures        Natural Gas Futures        
Current Assets  -   - Current Liabilities  9   4 
Deferred Charges  -   - Noncurrent Liabilities  -   5 
Other        Other        
Current Assets  -   - Current Liabilities  2   12 
Deferred Charges  -   - Noncurrent Liabilities  -   4 
  $14  $11   $30   52 
                  
        
Derivative Assets Derivative Liabilities 
  Fair Value   Fair Value 
  December 31 2009  December 31 2008   December 31 2009  December 31 2008 
Economic Hedges (In millions) Economic Hedges (In millions) 
NUG Contracts   NUG Contracts   
Power Purchase        Power Purchase        
Contract Asset $200  $434 Contract Liability $643  $766 
Other        Other        
Current Assets  -   1 Current Liabilities  106   1 
Deferred Charges  19   28 Noncurrent Liabilities  97   - 
  $219  $463   $846  $767 
Total Commodity Derivatives $233  $474 Total Commodity Derivatives $876  $819 

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 years ending December 31, 2009.

 Purchases Sales Net Units
 (In thousands)
Electricity Forwards11,684  (3,382) 8,302    MWH
Heating Oil Futures4,620  - 4,620    Gallons
Natural Gas Futures2,750  (2,250) 500    mmBtu

The effect of derivative instruments on the consolidated statements of income2011 and comprehensive income (loss) for December 31, 2009 and 2008, for instruments designated in cash flow hedging relationships and not in hedging relationships, respectively, are summarized in the following tables:

2010:
Derivatives in Cash Flow Hedging Relationships Electricity  Natural Gas  Heating Oil    
  Forwards  Futures  Futures  Total 
December 31, 2009 (in millions) 
Gain (Loss) Recognized in AOCL (Effective Portion) $7  $(9) $1  $(1)
Effective Gain (Loss) Reclassified to:(1)
                
Purchased Power Expense  (6)  -   -   (6)
Fuel Expense  -   (9)  (12)  (21)
                 
December 31, 2008                
Gain (Loss) Recognized in AOCL (Effective Portion) $3  $(4) $(18) $(19)
Effective Gain (Loss) Reclassified to:(1)
                
Purchased Power Expense  (6)  -   -   (6)
Fuel Expense  -   4   (2)  2 
  
Derivative Assets(1)
 
Derivative Liabilities(1)
 
Net(1)
  (In millions)
December 31, 2009 Balance $200
 $(643) $(443)
Realized gain (loss) —
 —
 —
Unrealized gain (loss) (71) (110) (181)
Purchases —
 —
 —
Issuances —
 —
 —
Sales —
 —
 —
Settlements (7) 287
 280
Transfers in (out) of Level 3 —
 —
 —
December 31, 2010 Balance $122
 $(466) $(344)
Realized gain (loss) —
 —
 —
Unrealized gain (loss) (55) (173) (228)
Purchases 13
 (4) 9
Issuances —
 —
 —
Sales —
 —
 —
Settlements (23) 283
 260
Transfers in (out) of Level 3 —
 (12) (12)
December 31, 2011 Balance $57
 $(372) $(315)
(1)The ineffective portion was immaterial.
206

Derivatives Not in Hedging Relationships
 NUG       
  Contracts  Other  Total 
2009 (In millions) 
Unrealized Gain (Loss) Recognized in:         
Purchased Power Expense $-  $(204) $(204)
Regulatory Assets(1)
  (470)  -   (470)
  $(470) $(204) $(674)
Realized Gain (Loss) Reclassified to:            
Regulatory Assets(1)
  (348)  -   (348)
  $(348) $-  $(348)
             
2008            
Unrealized Gain (Loss) Recognized in:            
Fuel Expense(2)
 $-  $1  $1 
Regulatory Assets(1)
  193   2   195 
  $193  $3  $196 
Realized Gain (Loss) Reclassified to:            
Fuel Expense(2)
 $-  $1  $1 
Regulatory Assets(1)
  (267)  -   (267)
  $(267) $1  $(266)
(1)
Changes in the fair value of NUG contracts are deferred for future recovery from (or refund to) customers.generally subject to regulatory accounting and do not impact earnings.
FES
  December 31, 2011 December 31, 2010
  Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets (In millions)
Corporate debt securities $—
 $1,010
 $—
 $1,010
 $—
 $528
 $—
 $528
Derivative assets — commodity contracts —
 248
 —
 248
 —
 241
 —
 241
Derivative assets — FTRs —
 —
 1
 1
 —
 —
 —
 —
Equity securities(1)
 124
 —
 —
 124
 —
 —
 —
 —
Foreign government debt securities —
 3
 —
 3
 —
 147
 —
 147
U.S. government debt securities —
 7
 —
 7
 —
 308
 —
 308
U.S. state debt securities —
 5
 —
 5
 —
 6
 —
 6
Other(2)
 —
 132
 —
 132
 —
 148
 —
 148
Total assets $124
 $1,405
 $1
 $1,530
 $—
 $1,378
 $—
 $1,378
Liabilities                
Derivative liabilities — commodity contracts $—
 $(234) $—
 $(234) $—
 $(348) $—
 $(348)
Derivative liabilities — FTRs —
 —
 (7) (7) —
 —
 —
 —
Total liabilities $—
 $(234) $(7) $(241) $—
 $(348) $—
 $(348)
Net assets (liabilities)(3)
 $124
 $1,171
 $(6) $1,289
 $—
 $1,030
 $—
 $1,030
(1)
NDT funds hold equity portfolios whose performance of which is benchmarked against the Alerian MLP Index.
(2)
Primarily consists of short-term cash investments.
(3)
The realized gain (loss) is reclassified upon terminationExcludes $(58) million and $7 million as of December 31, 2011 and 2010, respectively, of receivables, payables, taxes and accrued income associated with the derivative instrument.
financial instruments reflected within the fair value table.


220


Rollforward of Level 3 Measurements
Total unamortized losses includedThe following table provides a reconciliation of changes in AOCL associated with commodity derivatives were $15 million ($9 million net of tax) as of December 31, 2009, as compared to $44 million ($27 million net of tax) as of December 31, 2008. The net of tax change resulted from a $16 million decrease due to net hedge losses reclassified to earnings during 2009. Based on current estimates, approximately $9 million (after tax) of the net deferred losses on derivative instruments in AOCL as of December 31, 2009 are expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of FTRs held by FES and classified as Level 3 in the fair value hierarchy for the years ending December 31, 2011 and 2010:
  Derivative Asset FTRs Derivative Liability FTRs Net FTRs
  (In millions)
December 31, 2010 Balance $—
 $—
 $—
Realized gain (loss) —
 —
 —
Unrealized gain (loss) 4
 (8) (4)
Purchases 2
 (1) 1
Issuances —
 —
 —
Sales —
 —
 —
Settlements (5) 2
 (3)
Transfers in (out) of Level 3 —
 —
 —
December 31, 2011 Balance $1
 $(7) $(6)
OE
  December 31, 2011 December 31, 2010
  Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets (In millions)
Corporate debt securities $—
 $3
 $—
 $3
 $—
 $—
 $—
 $—
U.S. government debt securities —
 132
 —
 132
 —
 124
 —
 124
Other(1)
 —
 2
 —
 2
 —
 2
 —
 2
Total assets(2)
 $—
 $137
 $—
 $137
 $—
 $126
 $—
 $126
(1)
Primarily consists of short-term cash investments.
(2)
Excludes $1 million as of December 31, 2011 and 2010 of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.
TE
  December 31, 2011 December 31, 2010
  Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets (In millions)
Corporate debt securities $—
 $53
 $—
 $53
 $—
 $7
 $—
 $7
Equity securities(1)
 27
 —
 —
 27
 —
 —
 —
 —
U.S. government debt securities —
 —
 —
 —
 —
 33
 —
 33
U.S. state debt securities —
 —
 —
 —
 —
 1
 —
 1
Other(2)
 —
 3
 —
 3
 —
 35
 —
 35
Total assets $27
 $56
 $—
 $83
 $—
 $76
 $—
 $76
(1)
NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index.
(2)
Primarily consists of short-term cash investments.


221


JCP&L
  December 31, 2011 December 31, 2010
  Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets (In millions)
Corporate debt securities $—
 $144
 $—
 $144
 $—
 $23
 $—
 $23
Derivative assets — commodity contracts —
 —
 —
 —
 —
 2
 —
 2
Derivative assets — NUG contracts(1)
 —
 —
 4
 4
 —
 —
 6
 6
Equity securities(2)
 30
 —
 —
 30
 96
 —
 —
 96
U.S. government debt securities —
 2
 —
 2
 —
 33
 —
 33
U.S. state debt securities —
 219
 —
 219
 —
 236
 —
 236
Other(3)
 —
 15
 —
 15
 —
 4
 —
 4
Total assets $30
 $380
 $4
 $414
 $96
 $298
 $6
 $400
Liabilities                
Derivative liabilities — NUG contracts(1)
 $—
 $—
 $(147) $(147) $—
 $—
 $(233) $(233)
Total liabilities $—
 $—
 $(147) $(147) $—
 $—
 $(233) $(233)
Net assets (liabilities)(4)
 $30
 $380
 $(143) $267
 $96
 $298
 $(227) $167
(1)
NUG contracts are subject to regulatory accounting and do not impact earnings.
(2)
NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index.
(3)
Primarily consists of short-term cash investments.
(4)
Excludes $2 million and $(3) million as of December 31, 2011 and December 31, 2010 of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.
Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the fair value of NUG contracts held by JCP&L and classified as Level 3 in the fair value hierarchy for the years ending December 31, 2011 and 2010:
  
Derivative Asset NUG Contracts(1)
 
Derivative Liability NUG Contracts(1)
 
Net NUG Contracts(1)
  (In millions)
December 31, 2009 Balance $8
 $(399) $(391)
Realized gain (loss) —
 —
 —
Unrealized gain (loss) (1) 36
 35
Purchases —
 —
 —
Issuances —
 —
 —
Sales —
 —
 —
Settlements (1) 130
 129
Transfers in (out) of Level 3 —
 —
 —
December 31, 2010 Balance $6
 $(233) $(227)
Realized gain (loss) —
 —
 —
Unrealized gain (loss) (2) (11) (13)
Purchases —
 —
 —
Issuances —
 —
 —
Sales —
 —
 —
Settlements —
 97
 97
Transfers in (out) of Level 3 —
 —
 —
December 31, 2011 Balance $4
 $(147) $(143)
(1)
Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings.


222


MET-ED
  December 31, 2011 December 31, 2010
  Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets (In millions)
Corporate debt securities $—
 $229
 $—
 $229
 $—
 $32
 $—
 $32
Derivative assets — commodity contracts —
 —
 —
 —
 —
 5
 —
 5
Derivative assets — NUG contracts(1)
 —
 —
 49
 49
 —
 —
 112
 112
Equity securities(2)
 51
 —
 —
 51
 160
 —
 —
 160
Foreign government debt securities —
 —
 —
 —
 —
 1
 —
 1
U.S. government debt securities —
 5
 —
 5
 —
 88
 —
 88
U.S. state debt securities —
 —
 —
 —
 —
 2
 —
 2
Other(3)
 —
 23
 —
 23
 —
 14
 —
 14
Total assets $51
 $257
 $49
 $357
 $160
 $142
 $112
 $414
Liabilities                
Derivative liabilities — NUG contracts(1)
 $—
 $—
 $(79) $(79) $—
 $—
 $(116) $(116)
Total liabilities $—
 $—
 $(79) $(79) $—
 $—
 $(116) $(116)
Net assets (liabilities)(4)
 $51
 $257
 $(30) $278
 $160
 $142
 $(4) $298
(1)
NUG contracts are subject to regulatory accounting and do not impact earnings.
(2)
NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index.
(3)
Primarily consists of short-term cash investments.
(4)
Excludes $2 million and $(9) million as of December 31, 2011 and 2010, respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.
Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the fair value of NUG contracts held by Met-Ed and classified as Level 3 in the fair value hierarchy for the years ending December 31, 2011 and 2010:
  
Derivative Asset NUG Contracts(1)
 
Derivative Liability NUG Contracts(1)
 
Net
NUG Contracts(1)
  (In millions)
December 31, 2009 Balance $176
 $(143) $33
Realized gain (loss) —
 —
 —
Unrealized gain (loss) (59) (38) (97)
Purchases —
 —
 —
Issuances —
 —
 —
Sales —
 —
 —
Settlements (5) 65
 60
Transfers in (out) of Level 3 —
 —
 —
December 31, 2010 Balance $112
 $(116) $(4)
Realized gain (loss) —
 —
 —
Unrealized gain (loss) (57) (31) (88)
Purchases —
 —
 —
Issuances —
 —
 —
Sales —
 —
 —
Settlements (6) 68
 62
Transfers in (out) of Level 3 —
 —
 —
December 31, 2011 Balance $49
 $(79) $(30)
(1)
Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings.


223


PENELEC
  December 31, 2011 December 31, 2010
  Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets (In millions)
Corporate debt securities $—
 $104
 $—
 $104
 $—
 $8
 $—
 $8
Derivative assets — commodity contracts —
 —
 —
 —
 —
 2
 —
 2
Derivative assets — NUG contracts(1)
 —
 —
 3
 3
 —
 —
 4
 4
Equity securities(2)
 26
 —
 —
 26
 81
 —
 —
 81
U.S. government debt securities —
 2
 —
 2
 —
 9
 —
 9
U.S. state debt securities —
 90
 —
 90
 —
 133
 —
 133
Other(3)
 —
 39
 —
 39
 —
 5
 —
 5
Total assets $26
 $235
 $3
 $264
 $81
 $157
 $4
 $242
Liabilities                
Derivative liabilities — NUG contracts(1)
 $—
 $—
 $(123) $(123) $—
 $—
 $(117) $(117)
Total liabilities $—
 $—
 $(123) $(123) $—
 $—
 $(117) $(117)
Net assets (liabilities)(4)
 $26
 $235
 $(120) $141
 $81
 $157
 $(113) $125
(1)
NUG contracts are subject to regulatory accounting and do not impact earnings.
(2)
NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index.
(3)
Primarily consists of short-term cash investments.
(4)
Excludes $1 million and $(3) million as of December 31, 2011 and 2010, respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.
Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the fair value of NUG contracts held by Penelec and classified as Level 3 in the fair value hierarchy for the years ending December 31, 2011 and 2010:
  
Derivative Asset NUG Contracts(1)
 
Derivative Liability NUG Contracts(1)
 
Net
NUG Contracts(1)
  (In millions)
December 31, 2009 Balance $16
 $(101) $(85)
Realized gain (loss) —
 —
 —
Unrealized gain (loss) (11) (108) (119)
Purchases —
 —
 —
Issuances —
 —
 —
Sales —
 —
 —
Settlements (1) 92
 91
Transfers in (out) of Level 3 —
 —
 —
December 31, 2010 Balance $4
 $(117) $(113)
Realized gain (loss) —
 —
 —
Unrealized gain (loss) —
 (103) (103)
Purchases —
 —
 —
Issuances —
 —
 —
Sales —
 —
 —
Settlements (1) 97
 96
Transfers in (out) of Level 3 —
 —
 —
December 31, 2011 Balance $3
 $(123) $(120)
(1)
Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings.
During 2011, FirstEnergy received approximately $130 million from assigning a substantially below-market, long-term fossil fuel contract to a third party. As a result, FirstEnergy entered into a new long-term contract with another supplier for replacement fuel based on current market prices. The new contract runs for nine years, which is the remaining term of the assigned contract. The transaction reduced fuel costs during the year by approximately $123 million.
10. DERIVATIVE INSTRUMENTS


224


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’s Risk Policy Committee, comprised of senior management, provides general management oversight for risk management activities throughout FirstEnergy. The Risk Policy 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 practice. FirstEnergy also uses a variety of derivative instruments fluctuate from period to period basedfor risk management purposes including forward contracts, options, futures contracts and swaps.
FirstEnergy accounts for derivative instruments on various market factors.

Manyits Consolidated Balance Sheets at fair value unless they meet the normal purchases and normal sales criteria. Derivatives that meet those criteria are accounted for under the accrual method of FirstEnergy’s commodity derivatives contain credit risk features. Asaccounting, and their effects are included in earnings at the time of December 31, 2009, FirstEnergy posted $153 million of collateral related to net liability positions and held $26 million of 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 ifcontract performance. Changes in the credit rating for its debt were to fall below investment grade. The aggregate fair value of derivative instruments with credit risk-related contingent featuresthat qualified and were designated as cash flow hedge instruments are recorded in AOCI. Changes in the fair value of derivative instruments that are not designated as cash flow hedge instruments are recorded in a liability position on December 31, 2009 was $220 million, for which $127 million in collateral has been posted. If FirstEnergy’s credit rating were to fall below investment grade, it would be required to post $47 million of additional collateral related to commodity derivatives.

7.
LEASES

FirstEnergy leases certain generating facilities, office space and other property and equipment under cancelable and noncancelable leases.

In 1987, OE sold portions of its ownership interests in Perry Unit 1 and Beaver Valley Unit 2 and entered into operating leases on the portions sold for basic lease terms of approximately 29 years. In that same year, CEI and TE also sold portions of their ownership interests in Beaver Valley Unit 2 and Bruce Mansfield Units 1, 2 and 3 and entered into similar operating leases for lease terms of approximately 30 years. During the terms of their respective leases, OE, CEI and TE are responsible, to the extent of their leasehold interests, for costs associated with the units including construction expenditures, operation and maintenance expenses, insurance, nuclear fuel, property taxes and decommissioning. They have the right, at the expiration of the respective basic lease terms, to renew their respective leases. They also have the right to purchase the facilities at the expiration of the basic lease term or any renewal term at a price equal to the fair market value of the facilities. The basic rental payments are adjusted when applicable federal tax law changes.

207

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1, representing 779 MW of net demonstrated capacity. The purchase price of approximately $1.329 billion (net after-tax proceeds of approximately $1.2 billion) for the undivided interest was funded through a combination of equity investments by affiliates of AIG Financial Products Corp. and Union Bank of California, N.A. in six lessor trusts and proceeds from the sale of $1.135 billion aggregate principal amount of 6.85% pass through certificates due 2034. A like principal amount of secured notes maturing June 1, 2034 were issued by the lessor trusts to the pass through trust that issued and sold the certificates. The lessor trusts leased the undivided interest back to FGCO for a term of approximately 33 years under substantially identical leases. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. This transaction, which is classified as an operating lease for FES and FirstEnergy, generated tax capital gains of approximately $815 million, all of which were offset by existing tax capital loss carryforwards. Accordingly, FirstEnergy reduced its tax loss carryforward valuation allowances in 2007, with a corresponding reduction to goodwill (see Note 2(E)).

Effective October 16, 2007 CEI and TE assigned their leasehold interests in the Bruce Mansfield Plant to FGCO and 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 13, 2007 Bruce Mansfield Unit 1 sale and leaseback transaction, to a newly formed wholly-owned subsidiary on December 17, 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. 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.

During 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.

Rentals for capital and operating leases for the three years ended December 31, 2009 are summarized as follows:

  FE  FES  OE  CEI  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
2009                        
Operating leases
 $236  $202  $146  $4  $64  $9  $7  $4 
Capital leases
                                
Interest element
  1   2   1   1   -   -   -   - 
Other(1)
  6   10   -   -   -   -   -   - 
Total rentals
 $243  $214  $147  $5  $64  $9  $7  $4 
                                 
2008
                                
Operating leases $381  $173  $146  $5  $65  $8  $4  $4 
Capital leases
                                
Interest element
  1   1   -   -   -   -   -   - 
Other(1)
  6   8   -   1   -   -   -   - 
Total rentals
 $388  $182  $146  $6  $65  $8  $4  $4 
                                 
2007
                                
Operating leases $376  $45  $145  $62  $101  $8  $4  $5 
Capital leases
                                
Interest element
  -   -   -   -   -   -   -   - 
Other
  1   -   -   1   -   -   -   - 
Total rentals
 $377  $45  $145  $63  $101  $8  $4  $5 
(1)
Includes $6 million and $5 million in 2009 and 2008, respectively, for wind purchased power agreements classified as capital leases.
The future minimum capital lease payments as of December 31, 2009 are as follows (TE, JCP&L, Met-Ed and Penelec have no material capital leases):

208

Capital Leases FE  FES  OE  CEI 
  (In millions) 
2010 $2  $6  $-  $1 
2011  2   6   -   1 
2012  1   6   1   1 
2013  1   6   -   1 
2014  1   6   -   1 
Years thereafter  3   18   -   3 
Total minimum lease payments  10   48   1   8 
Executory costs  -   -   -   - 
Net minimum lease payments  10   48   1   8 
Interest portion  6   6   -   6 
Present value of net minimum lease payments  4   42   1   2 
Less current portion  -   4   -   - 
Noncurrent portion $4  $38  $1  $2 


The present value of minimum lease payments for FirstEnergy does not include $9 million of capital lease obligations that were prepaid at December 31, 2009.

Established by OE in 1996, PNBV purchased a portion of the lease obligation bonds issued on behalf of lessors in OE's Perry Unit 1 and Beaver Valley Unit 2 sale and leaseback transactions. Similarly, CEI and TE established Shippingport in 1997 to purchase the lease obligation bonds issued on behalf of lessors in their Bruce Mansfield Units 1, 2 and 3 sale and leaseback transactions. The PNBV and Shippingport arrangements effectively reduce lease costs related to those transactions (see Note 8).

The future minimum operating lease payments as of December 31, 2009 are as follows:

Operating Leases FE Lease Payments  FE Capital Trusts  FE Net 
          
2010
 $341  $116  $225 
2011
  323   116   207 
2012
  360   125   235 
2013
  362   130   232 
2014
  358   131   227 
Years thereafter
  2,482   123   2,359 
Total minimum lease payments
 $4,226  $741  $3,485 
Operating Leases FES  OE  CEI  TE  JCP&L  Met-Ed  Penelec 
                      
2010
 $199  $146  $4  $64  $6  $7  $3 
2011
  190   146   3   64   5   4   3 
2012
  229   146   3   64   5   3   2 
2013
  235   145   3   64   5   3   2 
2014
  234   145   2   64   4   3   2 
Years thereafter
  2,133   305   5   140   49   35   20 
Total minimum lease      payments
 $3,220  $1,033  $20  $460  $74  $55  $32 

FirstEnergy recorded above-market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant associated with the 1997 merger between OE and Centerior. The unamortized above-market lease liability for Beaver Valley Unit 2 of $236 million as of December 31, 2009, of which $37 million is classified as current, is being amortized by TEincome on a straight-line basismark-to-market basis. FirstEnergy has contractual derivative agreements through the end of the lease term in 2017. The unamortized above-market lease liability for the Bruce Mansfield Plant of $308 million as of December 31, 2009, of which $46 million is classified as current, is being amortized by FGCO on a straight-line basis through the end of the lease term in 2016.2018.

8.VARIABLE INTEREST ENTITIES

FirstEnergy and its subsidiaries consolidate VIEs when they are determined to be the VIE's primary beneficiary. FirstEnergy and its subsidiaries reflect the portion of VIEs not owned by them in the caption noncontrolling interest within the consolidated financial statements. The change in noncontrolling interest during 2009 is the result of net losses of the noncontrolling interests ($16 million), the acquisition of additional interest in certain joint ventures and other adjustments ($13 million), and distributions to owners ($5 million).

209

Mining Operations

On July 16,In 2008, FEV entered into a joint venture with the Boich Companies, a Columbus, Ohio-based coal company, to acquire a majority stake in the Signal Peak mining and coal transportation operations near Roundup, Montana. FEV made equity investments totaling $133.5 million in exchange for a $125 million equity investment in the joint venture, which acquired 80% of the mining operations (Signal Peak Energy, LLC) and 100% of the transportation operations, with FEV owning a 45% economic interest and an affiliate of the Boich Companies owning a 55%50% economic interest in the joint venture. Both parties haveOn October 18, 2011, a 50% voting interest in the joint venture. FEV consolidates the mining and transportation operationssubsidiary of this joint venture in its financial statements. In March 2009, FEV agreed to payGunvor Group, Ltd purchased a total of $8.5 million to affiliates of the Boich Companies to purchase an additional 5% economicone-third interest in the Signal Peak miningjoint venture in which FEV held a 50% interest. As part of the transaction, FirstEnergy received $257.5 million in proceeds and coal transportation operations. Voting interests remained unchanged after the sale was completedretained a 33-1/3% equity ownership 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. For both acquisitions, the difference between the consideration paid and the adjustment to the noncontrolling interestventure. The sale resulted in a charge to other paid in capitalpre-tax gain of approximately $30 million.$569 million ($370 million after-tax), which includes $378.6 million from the remeasurement of FEV's retained investment. The gain attributed to the retained investment remeasurement will be amortized as coal is extracted from the mine on a units of production method.

(In millions) 
Fair value of retained noncontrolling investment$400.0
Less: Carrying value of retained interest21.4
Gain on retained interest$378.6
FirstEnergy previously consolidated this joint venture and, as a result of the sale, its retained 33-1/3% interest is accounted for using the equity method of accounting.
Trusts

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

PNBV was established to purchase a portion of the lease obligation bonds issued in connection with OE's 1987 sale and leaseback of its interests in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by PNBV for the purchase of lease obligation bonds. Ownership of PNBV includes a 3% equity interest by an unaffiliated third party and a 3% equity interest held by OES Ventures, a wholly owned subsidiary of OE. Shippingport was established to purchase all of the lease obligation bonds issued in connection with CEI's and TE's Bruce Mansfield Plant sale and leaseback transaction in 1987. CEI and TE used debt and available funds to purchase the notes issued by Shippingport.
PATH-WV
PATH, LLC was formed to construct, through its operating companies, the PATH Project, which is a high-voltage transmission line that was proposed to extend from West Virginia through Virginia and into Maryland, including modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland as directed by PJM. PATH, LLC is a series limited liability company that is comprised of multiple series, each of which has separate rights, powers and duties regarding specified property and the series profits and losses associated with such property. A subsidiary of AE owns 100% of the Allegheny Series and 50% of the West Virginia Series (PATH-WV), which is a joint venture with a subsidiary of AEP. FirstEnergy is not the primary beneficiary of PATH-WV, as it does not have control over the significant activities affecting the economics of the portion of the PATH Project to be constructed by PATH-WV.
Because of the nature of PATH-WV's operations and its FERC approved rate mechanism, FirstEnergy's maximum exposure to loss consists of its equity investment in PATH-WV, which was $29 million as of December 31, 2011.


214


Power Purchase Agreements
FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities may be VIEs to the extent that they own a plant that sells substantially all of its output to certain of the Utilities if the contract price for power is correlated with the plant's variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed, Penelec, PE, WP and MP, maintains 23 long-term power purchase agreements with NUG entities that were entered into pursuant to PURPA. 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 four of these NUG entities, it does not have a variable interest in the NUG entities or the NUG entities do not meet the criteria to be considered a VIE. JCP&L, PE and WP may hold variable interests in the remaining four entities; however, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities.
Because JCP&L, PE and WP have no equity or debt interests in the NUG entities, their maximum exposure to loss relates primarily to the above-market costs incurred for power. FirstEnergy expects any above-market costs incurred by its subsidiaries to be recovered from customers, except as described further below. Purchased power costs related to the four contracts that may contain a variable interest that were held by FirstEnergy subsidiaries during the year ended December 31, 2011 were $176 million, $101.6 million and $48.9 million for JCP&L, PE and WP, respectively. Purchased power costs related to the two contracts that may contain a variable interest that were held by JCP&L during the years ended December 31, 2010 and 2009 were $243 million and $225 million, respectively.
In 1998 the PPUC issued an order approving a transition plan for WP that disallowed certain costs, including an estimated amount for an adverse power purchase commitment related to the NUG entity for which WP may hold a variable interest. As of December 31, 2011, WP's reserve for this adverse purchase power commitment was $53 million, including a current liability of $11 million, and is being amortized over the life of the commitment.
Loss Contingencies

FirstEnergy has variable interests in certain sale-leaseback transactions. FirstEnergy is not the primary beneficiary of these interests as it does not have control over the significant activities affecting the economics of the 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 would render the applicable plant worthless. Net discounted lease payments would not be payable if the casualty loss payments arewere made. The following table showsdiscloses each company’s net exposure to loss based upon the casualty value provisions mentioned above:above as of December 31, 2011:

 Maximum Exposure  
Discounted Lease Payments, net(1)
  Net Exposure  
Maximum
Exposure
 
Discounted Lease
Payments, net(1)
 
Net
Exposure
 (in millions)  (In millions)
FES $1,348  $1,175  $173  $1,362
 $1,159
 $203
OE  723   526   197  606
 416
 190
CEI  665   75   590 
TE  665   382   283 
CEI(2)
 587
 71
 516
TE(2)
 587
 309
 278
(1)
The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments was $1.7is $1.6 billion as of December 31, 2009.
(2)
(see NGC lessor equity interest purchases described in Note 7).CEI and TE are jointly and severally liable for the maximum loss amounts under certain sale-leaseback agreements.

See Note 76, Leases, for a discussion of CEI’sCEI's and TE’sTE's assignment of their leasehold interestsinterest in the Bruce Mansfield Plant to FGCO.
9. FAIR VALUE MEASUREMENTS
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS
Power Purchase AgreementsAll borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are reported on the Consolidated Balance Sheets at cost, which approximates their fair market value, in the caption “Short-term borrowings.” The following table provides the approximate fair value and related carrying amounts of long-term debt and other long-term obligations, excluding capital lease obligations and net unamortized premiums and discounts, as of December 31, 2011 and 2010:


215


  December 31, 2011 December 31, 2010
  Carrying Value Fair Value Carrying Value Fair Value
  (In millions)
FirstEnergy(1)
 $17,165
 $19,320
 $13,928
 $14,845
FES 3,675
 3,931
 4,279
 4,403
OE 1,157
 1,434
 1,159
 1,321
CEI 1,831
 2,162
 1,853
 2,035
TE 600
 741
 600
 653
JCP&L 1,777
 2,080
 1,810
 1,962
Met-Ed 729
 824
 742
 821
Penelec 1,120
 1,251
 1,120
 1,189
(1)
Includes debt assumed in the AE merger (see Note 2, Merger) with a carrying value and a fair value as of December 31, 2011, of $4,355 million and $4,561 million, respectively.
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 FirstEnergy evaluatedand its power purchase agreementssubsidiaries listed above.
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 determinedcash equivalents include held-to-maturity securities, available-for-sale securities and notes receivable.
FE and its subsidiaries 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, FE and its subsidiaries consider their intent to hold the security, the likelihood that certain NUG entities maythey will be VIEsrequired to sell the security before recovery of their cost basis and the likelihood of recovery of the security’s entire amortized cost basis.
Unrealized gains applicable to the extent they own a plant that sells substantially alldecommissioning trusts of its outputFES, OE and TE are recognized in OCI because fluctuations in fair value will eventually impact earnings while unrealized losses are recorded to the Utilities and the contract price for power is correlated with the plant's variable costsearnings. The decommissioning trusts of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed and Penelec maintains 26 long-term power purchase agreements with NUG entities. The agreements were entered into pursuantare subject to regulatory accounting. Net unrealized gains and losses are recorded as regulatory assets or liabilities because the Public Utility Regulatory Policies Act of 1978. FirstEnergy was not involveddifference between investments held in the creation of,trust and has no equity or debt invested in, these entities.

210

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 incurs for power. FirstEnergy expects any above-market costs it incurs todecommissioning liabilities will be recovered from or refunded to customers. Purchased
The investment policy for the NDT funds restricts or limits the trusts’ ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power costs from these entities during 2009, 2008,plants, financial derivatives, preferred stocks, securities convertible into common stock and 2007 were $165 million, $178 million,securities of the trust funds’ custodian or managers and $176 million, respectively.their parents or subsidiaries.
Available-For-Sale Securities
FES and the Utility Registrants hold debt and equity securities within their NDT, nuclear fuel disposal trusts and NUG trusts. These trust investments are considered available-for-sale securities at fair market value. FES and the Utility Registrants have no securities held for trading purposes.
The following table summarizes the amortized cost basis, unrealized gains and losses and fair values of investments held in NDT, nuclear fuel disposal trusts and NUG trusts as of December 31, 2011 and 2010:


  2009  2008  2007 
  (In millions) 
JCP&L $73  $84  $90 
Met-Ed  57   61   56 
Penelec  35   33   30 
Total $165  $178  $176 
216


9.     DIVESTITURES

  
December 31, 2011(1)
 
December 31, 2010(2)
  Cost Basis Unrealized Gains Unrealized Losses Fair Value Cost Basis Unrealized Gains Unrealized Losses Fair Value
  (In millions)
Debt securities                
FirstEnergy $1,980
 $25
 $—
 $2,005
 $1,699
 $31
 $—
 $1,730
FES 1,012
 13
 —
 1,025
 980
 13
 —
 993
OE 134
 —
 —
 134
 123
 1
 —
 124
TE 53
 1
 —
 54
 42
 —
 —
 42
JCP&L 356
 7
 —
 363
 281
 9
 —
 290
Met-Ed 232
 2
 —
 234
 127
 4
 —
 131
Penelec 193
 2
 —
 195
 145
 4
 —
 149
Equity securities                
FirstEnergy $222
 $36
 $—
 $258
 $268
 $69
 $—
 $337
FES 104
 20
 —
 124
 —
 —
 —
 —
TE 22
 5
 —
 27
 —
 —
 —
 —
JCP&L 27
 3
 —
 30
 80
 17
 —
 97
Met-Ed 46
 5
 —
 51
 125
 35
 —
 160
Penelec 23
 3
 —
 26
 63
 16
 —
 79
(1)
Excludes short-term cash investments: FirstEnergy — $164 million; FES — $74 million; OE — $2 million; TE — $2 million; JCP&L — $19 million; Met-Ed — $25 million and Penelec — $41 million.
(2)
Excludes short-term cash investments: FirstEnergy — $193 million; FES — $153 million; OE — $3 million; TE — $34 million; JCP&L — $3 million; Met-Ed — $(3) million and Penelec — $4 million.
On March 7, 2008, FirstEnergy sold certain telecommunication assets, resulting in a net after-tax gain of $19.3 million. TheProceeds from the sale of assets did not meet the criteria for classification as discontinued operations asinvestments in available-for-sale securities, realized gains and losses on those sales net of December 31, 2008.

10.  TAXES

Income Taxes

FirstEnergy recordsadjustments recorded to earnings and interest and dividend income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to temporary tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled. Details of income taxes for the three years ended December 31, 2011, 2010 and 2009 are shown below: were as follows:
December 31, 2011 Sales Proceeds Realized Gains Realized Losses 
Interest and
Dividend Income
  (In millions)
FirstEnergy $4,207
 $229
 $(90) $82
FES 1,843
 80
 (46) 47
OE 154
 6
 —
 3
TE 120
 5
 (5) 2
JCP&L 779
 39
 (11) 15
Met-Ed 860
 64
 (16) 8
Penelec 451
 35
 (12) 6
December 31, 2010 Sales Proceeds Realized Gains Realized Losses Interest and Dividend Income
  (In millions)
FirstEnergy $3,172
 $126
 $(107) $79
FES 1,927
 92
 (75) 47
OE 83
 2
 —
 3
TE 126
 3
 (1) 2
JCP&L 411
 10
 (10) 14
Met-Ed 460
 13
 (14) 7
Penelec 165
 6
 (7) 6


217


211
December 31, 2009 Sales Proceeds Realized Gains Realized Losses Interest and Dividend Income
  (In millions)
FirstEnergy $2,229
 $226
 $(155) $60
FES 1,379
 199
 (117) 27
OE 131
 11
 (4) 4
TE 169
 7
 (1) 2
JCP&L 397
 6
 (12) 14
Met-Ed 68
 2
 (13) 7
Penelec 84
 1
 (8) 6
Held-To-Maturity Securities
The following table provides the amortized cost basis, unrealized gains and approximate fair values of investments in held-to-maturity securities as of December 31, 2011 and 2010:
  December 31, 2011 December 31, 2010
  Cost Basis Unrealized Gains Fair Value Cost Basis Unrealized Gains Fair Value
  (In millions)
Debt Securities            
FirstEnergy $402
 $50
 $452
 $476
 $91
 $567
OE 163
 21
 184
 190
 51
 241
CEI 287
 28
 315
 340
 41
 381
Investments in emission allowances, employee benefit trusts and cost and equity method investments totaling $693 million as of December 31, 2011, and $259 million as of December 31, 2010, are excluded from the amounts reported above.
Notes Receivable
The table below provides the approximate fair value and related carrying amounts of notes receivable as of December 31, 2011 and 2010. The fair value of notes receivable represents the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms. The maturity date of notes receivable due from affiliated companies is 2016.
  December 31, 2011 December 31, 2010
  Carrying Value Fair Value Carrying Value Fair Value
  (In millions)
FirstEnergy $—
 $—
 $7
 $8
TE(1)
 81
 92
 104
 118
(1)
Represents TE's investment in the Shippingport Trust notes (see Note 6, Leases), which is eliminated during consolidation.
RECURRING FAIR VALUE MEASUREMENTS
Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. The three levels of the fair value hierarchy are as follows:


PROVISION FOR INCOME TAXES FE  FES  OE  CEI  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
2009                        
Currently payable-                        
Federal $(183) $87  $21  $40  $6  $40  $(34) $(21)
State  44   8   4   2   -   26   (4)  4 
   (139)  95   25   42   6   66   (38)  (17)
Deferred, net-                                
Federal  351   200   40   (52)  -   41   60   60 
State  42   24   3   1   2   2   7   4 
   393   224   43   (51)  2   43   67   64 
Investment tax credit amortization  (9)  (4)  (2)  (1)  -   -   -   (1)
Total provision for income taxes $245  $315  $66  $(10) $8  $109  $29  $46 
                                 
2008                                
Currently payable-                                
Federal $355  $156  $79  $119  $46  $101  $5  $(34)
State  56   20   4   6   -   34   6   (3)
   411   176   83   125   46   135   11   (37)
Deferred, net-                                
Federal  343   109   22   16   (12)  9   47   84 
State  36   12   (2)  (2)  (4)  4   4   12 
   379   121   20   14   (16)  13   51   96 
Investment tax credit amortization  (13)  (4)  (4)  (2)  -   -   (1)  (1)
Total provision for income taxes $777  $293  $99  $137  $30  $148  $61  $58 
                                 
2007       
Currently payable-                                
Federal $706  $528  $105  $166  $73  $138  $26  $41 
State  187   111   (4)  20   7   42   7   12 
   893   639   101   186   80   180   33   53 
Deferred, net-                                
Federal  22   (288)  -   (23)  (27)  (25)  30   10 
State  (18)  (42)  4   2   2   (5)  6   1 
   4   (330)  4   (21)  (25)  (30)  36   11 
Investment tax credit amortization  (14)  (4)  (4)  (2)  (1)  (1)  (1)  - 
Total provision for income taxes $883  $305  $101  $163  $54  $149  $68  $64 
218


Level 1– Quoted prices for identical instruments in active markets.
Level 2– Quoted prices for similar instruments in active markets;
– quoted prices for identical or similar instruments in markets that are not active and
– model-derived valuations for which all significant inputs are observable market data.
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.
Level 3– Valuation inputs are unobservable and significant to the fair value measurement.
FirstEnergy develops its view of the future market price through a combination of market observation and assessment (generally for the short term) and fundamental modeling (generally for the long term). 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 determination of the fair value measures takes into consideration various factors. These factors include, but are not limited to, nonperformance risk, including counterparty credit risk and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of these forms of risk were not significant in the fair value measurements.
The following tables set forth financial assets and liabilities that are accounted for at fair value by level within the fair value hierarchy. There were no significant transfers between levels during 2011 and 2010.
FIRSTENERGY
  December 31, 2011 December 31, 2010
  Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets (In millions)
Corporate debt securities $—
 $1,544
 $—
 $1,544
 $—
 $597
 $—
 $597
Derivative assets — commodity contracts —
 264
 —
 264
 —
 250
 —
 250
Derivative assets — FTRs —
 —
 1
 1
 —
 —
 —
 —
Derivative assets — NUG contracts(1)
 —
 —
 56
 56
 —
 —
 122
 122
Equity securities(2)
 259
 —
 —
 259
 338
 —
 —
 338
Foreign government debt securities —
 3
 —
 3
 —
 149
 —
 149
U.S. government debt securities —
 148
 —
 148
 —
 595
 —
 595
U.S. state debt securities —
 314
 —
 314
 —
 379
 —
 379
Other(3)
 —
 225
 —
 225
 —
 219
 —
 219
Total assets $259
 $2,498
 $57
 $2,814
 $338
 $2,189
 $122
 $2,649
Liabilities                
Derivative liabilities — commodity contracts $—
 $(247) $—
 $(247) $—
 $(348) $—
 $(348)
Derivative liabilities — FTRs —
 —
 (23) (23) —
 —
 —
 —
Derivative liabilities — NUG contracts(1)
 —
 —
 (349) (349) —
 —
 (466) (466)
Total liabilities $—
 $(247) $(372) $(619) $—
 $(348) $(466) $(814)
Net assets (liabilities)(4)
 $259
 $2,251
 $(315) $2,195
 $338
 $1,841
 $(344) $1,835
(1)
NUG contracts are generally subject to regulatory accounting and do not impact earnings.
(2)
NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index.
(3)
Primarily consists of short-term cash investments.
(4)
Excludes $(52) million and $(7) million as of December 31, 2011 and 2010, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.


219


Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the fair value of NUG contracts held by the Utilities and FTRs held by FirstEnergy and classified as Level 3 in the fair value hierarchy for the years ending December 31, 2011 and 2010:
  
Derivative Assets(1)
 
Derivative Liabilities(1)
 
Net(1)
  (In millions)
December 31, 2009 Balance $200
 $(643) $(443)
Realized gain (loss) —
 —
 —
Unrealized gain (loss) (71) (110) (181)
Purchases —
 —
 —
Issuances —
 —
 —
Sales —
 —
 —
Settlements (7) 287
 280
Transfers in (out) of Level 3 —
 —
 —
December 31, 2010 Balance $122
 $(466) $(344)
Realized gain (loss) —
 —
 —
Unrealized gain (loss) (55) (173) (228)
Purchases 13
 (4) 9
Issuances —
 —
 —
Sales —
 —
 —
Settlements (23) 283
 260
Transfers in (out) of Level 3 —
 (12) (12)
December 31, 2011 Balance $57
 $(372) $(315)
(1)
Changes in the fair value of NUG contracts are generally subject to regulatory accounting and do not impact earnings.
FES
  December 31, 2011 December 31, 2010
  Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets (In millions)
Corporate debt securities $—
 $1,010
 $—
 $1,010
 $—
 $528
 $—
 $528
Derivative assets — commodity contracts —
 248
 —
 248
 —
 241
 —
 241
Derivative assets — FTRs —
 —
 1
 1
 —
 —
 —
 —
Equity securities(1)
 124
 —
 —
 124
 —
 —
 —
 —
Foreign government debt securities —
 3
 —
 3
 —
 147
 —
 147
U.S. government debt securities —
 7
 —
 7
 —
 308
 —
 308
U.S. state debt securities —
 5
 —
 5
 —
 6
 —
 6
Other(2)
 —
 132
 —
 132
 —
 148
 —
 148
Total assets $124
 $1,405
 $1
 $1,530
 $—
 $1,378
 $—
 $1,378
Liabilities                
Derivative liabilities — commodity contracts $—
 $(234) $—
 $(234) $—
 $(348) $—
 $(348)
Derivative liabilities — FTRs —
 —
 (7) (7) —
 —
 —
 —
Total liabilities $—
 $(234) $(7) $(241) $—
 $(348) $—
 $(348)
Net assets (liabilities)(3)
 $124
 $1,171
 $(6) $1,289
 $—
 $1,030
 $—
 $1,030
(1)
NDT funds hold equity portfolios whose performance of which is benchmarked against the Alerian MLP Index.
(2)
Primarily consists of short-term cash investments.
(3)
Excludes $(58) million and $7 million as of December 31, 2011 and 2010, respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.


220


Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the fair value of FTRs held by FES and classified as Level 3 in the Utilities are party to an intercompany income tax allocation agreement with FirstEnergy and its other subsidiaries that providesfair value hierarchy for the years ending December 31, 2011 and 2010:
  Derivative Asset FTRs Derivative Liability FTRs Net FTRs
  (In millions)
December 31, 2010 Balance $—
 $—
 $—
Realized gain (loss) —
 —
 —
Unrealized gain (loss) 4
 (8) (4)
Purchases 2
 (1) 1
Issuances —
 —
 —
Sales —
 —
 —
Settlements (5) 2
 (3)
Transfers in (out) of Level 3 —
 —
 —
December 31, 2011 Balance $1
 $(7) $(6)
OE
  December 31, 2011 December 31, 2010
  Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets (In millions)
Corporate debt securities $—
 $3
 $—
 $3
 $—
 $—
 $—
 $—
U.S. government debt securities —
 132
 —
 132
 —
 124
 —
 124
Other(1)
 —
 2
 —
 2
 —
 2
 —
 2
Total assets(2)
 $—
 $137
 $—
 $137
 $—
 $126
 $—
 $126
(1)
Primarily consists of short-term cash investments.
(2)
Excludes $1 million as of December 31, 2011 and 2010 of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.
TE
  December 31, 2011 December 31, 2010
  Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets (In millions)
Corporate debt securities $—
 $53
 $—
 $53
 $—
 $7
 $—
 $7
Equity securities(1)
 27
 —
 —
 27
 —
 —
 —
 —
U.S. government debt securities —
 —
 —
 —
 —
 33
 —
 33
U.S. state debt securities —
 —
 —
 —
 —
 1
 —
 1
Other(2)
 —
 3
 —
 3
 —
 35
 —
 35
Total assets $27
 $56
 $—
 $83
 $—
 $76
 $—
 $76
(1)
NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index.
(2)
Primarily consists of short-term cash investments.


221


JCP&L
  December 31, 2011 December 31, 2010
  Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets (In millions)
Corporate debt securities $—
 $144
 $—
 $144
 $—
 $23
 $—
 $23
Derivative assets — commodity contracts —
 —
 —
 —
 —
 2
 —
 2
Derivative assets — NUG contracts(1)
 —
 —
 4
 4
 —
 —
 6
 6
Equity securities(2)
 30
 —
 —
 30
 96
 —
 —
 96
U.S. government debt securities —
 2
 —
 2
 —
 33
 —
 33
U.S. state debt securities —
 219
 —
 219
 —
 236
 —
 236
Other(3)
 —
 15
 —
 15
 —
 4
 —
 4
Total assets $30
 $380
 $4
 $414
 $96
 $298
 $6
 $400
Liabilities                
Derivative liabilities — NUG contracts(1)
 $—
 $—
 $(147) $(147) $—
 $—
 $(233) $(233)
Total liabilities $—
 $—
 $(147) $(147) $—
 $—
 $(233) $(233)
Net assets (liabilities)(4)
 $30
 $380
 $(143) $267
 $96
 $298
 $(227) $167
(1)
NUG contracts are subject to regulatory accounting and do not impact earnings.
(2)
NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index.
(3)
Primarily consists of short-term cash investments.
(4)
Excludes $2 million and $(3) million as of December 31, 2011 and December 31, 2010 of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.
Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the fair value of NUG contracts held by JCP&L and classified as Level 3 in the fair value hierarchy for the years ending December 31, 2011 and 2010:
  
Derivative Asset NUG Contracts(1)
 
Derivative Liability NUG Contracts(1)
 
Net NUG Contracts(1)
  (In millions)
December 31, 2009 Balance $8
 $(399) $(391)
Realized gain (loss) —
 —
 —
Unrealized gain (loss) (1) 36
 35
Purchases —
 —
 —
Issuances —
 —
 —
Sales —
 —
 —
Settlements (1) 130
 129
Transfers in (out) of Level 3 —
 —
 —
December 31, 2010 Balance $6
 $(233) $(227)
Realized gain (loss) —
 —
 —
Unrealized gain (loss) (2) (11) (13)
Purchases —
 —
 —
Issuances —
 —
 —
Sales —
 —
 —
Settlements —
 97
 97
Transfers in (out) of Level 3 —
 —
 —
December 31, 2011 Balance $4
 $(147) $(143)
(1)
Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings.


222


MET-ED
  December 31, 2011 December 31, 2010
  Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets (In millions)
Corporate debt securities $—
 $229
 $—
 $229
 $—
 $32
 $—
 $32
Derivative assets — commodity contracts —
 —
 —
 —
 —
 5
 —
 5
Derivative assets — NUG contracts(1)
 —
 —
 49
 49
 —
 —
 112
 112
Equity securities(2)
 51
 —
 —
 51
 160
 —
 —
 160
Foreign government debt securities —
 —
 —
 —
 —
 1
 —
 1
U.S. government debt securities —
 5
 —
 5
 —
 88
 —
 88
U.S. state debt securities —
 —
 —
 —
 —
 2
 —
 2
Other(3)
 —
 23
 —
 23
 —
 14
 —
 14
Total assets $51
 $257
 $49
 $357
 $160
 $142
 $112
 $414
Liabilities                
Derivative liabilities — NUG contracts(1)
 $—
 $—
 $(79) $(79) $—
 $—
 $(116) $(116)
Total liabilities $—
 $—
 $(79) $(79) $—
 $—
 $(116) $(116)
Net assets (liabilities)(4)
 $51
 $257
 $(30) $278
 $160
 $142
 $(4) $298
(1)
NUG contracts are subject to regulatory accounting and do not impact earnings.
(2)
NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index.
(3)
Primarily consists of short-term cash investments.
(4)
Excludes $2 million and $(9) million as of December 31, 2011 and 2010, respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.
Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the fair value of NUG contracts held by Met-Ed and classified as Level 3 in the fair value hierarchy for the years ending December 31, 2011 and 2010:
  
Derivative Asset NUG Contracts(1)
 
Derivative Liability NUG Contracts(1)
 
Net
NUG Contracts(1)
  (In millions)
December 31, 2009 Balance $176
 $(143) $33
Realized gain (loss) —
 —
 —
Unrealized gain (loss) (59) (38) (97)
Purchases —
 —
 —
Issuances —
 —
 —
Sales —
 —
 —
Settlements (5) 65
 60
Transfers in (out) of Level 3 —
 —
 —
December 31, 2010 Balance $112
 $(116) $(4)
Realized gain (loss) —
 —
 —
Unrealized gain (loss) (57) (31) (88)
Purchases —
 —
 —
Issuances —
 —
 —
Sales —
 —
 —
Settlements (6) 68
 62
Transfers in (out) of Level 3 —
 —
 —
December 31, 2011 Balance $49
 $(79) $(30)
(1)
Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings.


223


PENELEC
  December 31, 2011 December 31, 2010
  Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets (In millions)
Corporate debt securities $—
 $104
 $—
 $104
 $—
 $8
 $—
 $8
Derivative assets — commodity contracts —
 —
 —
 —
 —
 2
 —
 2
Derivative assets — NUG contracts(1)
 —
 —
 3
 3
 —
 —
 4
 4
Equity securities(2)
 26
 —
 —
 26
 81
 —
 —
 81
U.S. government debt securities —
 2
 —
 2
 —
 9
 —
 9
U.S. state debt securities —
 90
 —
 90
 —
 133
 —
 133
Other(3)
 —
 39
 —
 39
 —
 5
 —
 5
Total assets $26
 $235
 $3
 $264
 $81
 $157
 $4
 $242
Liabilities                
Derivative liabilities — NUG contracts(1)
 $—
 $—
 $(123) $(123) $—
 $—
 $(117) $(117)
Total liabilities $—
 $—
 $(123) $(123) $—
 $—
 $(117) $(117)
Net assets (liabilities)(4)
 $26
 $235
 $(120) $141
 $81
 $157
 $(113) $125
(1)
NUG contracts are subject to regulatory accounting and do not impact earnings.
(2)
NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index.
(3)
Primarily consists of short-term cash investments.
(4)
Excludes $1 million and $(3) million as of December 31, 2011 and 2010, respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.
Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the fair value of NUG contracts held by Penelec and classified as Level 3 in the fair value hierarchy for the years ending December 31, 2011 and 2010:
  
Derivative Asset NUG Contracts(1)
 
Derivative Liability NUG Contracts(1)
 
Net
NUG Contracts(1)
  (In millions)
December 31, 2009 Balance $16
 $(101) $(85)
Realized gain (loss) —
 —
 —
Unrealized gain (loss) (11) (108) (119)
Purchases —
 —
 —
Issuances —
 —
 —
Sales —
 —
 —
Settlements (1) 92
 91
Transfers in (out) of Level 3 —
 —
 —
December 31, 2010 Balance $4
 $(117) $(113)
Realized gain (loss) —
 —
 —
Unrealized gain (loss) —
 (103) (103)
Purchases —
 —
 —
Issuances —
 —
 —
Sales —
 —
 —
Settlements (1) 97
 96
Transfers in (out) of Level 3 —
 —
 —
December 31, 2011 Balance $3
 $(123) $(120)
(1)
Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings.
During 2011, FirstEnergy received approximately $130 million from assigning a substantially below-market, long-term fossil fuel contract to a third party. As a result, FirstEnergy entered into a new long-term contract with another supplier for replacement fuel based on current market prices. The new contract runs for nine years, which is the remaining term of the assigned contract. The transaction reduced fuel costs during the year by approximately $123 million.
10. DERIVATIVE INSTRUMENTS


224


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’s Risk Policy Committee, comprised of senior management, provides general management oversight for risk management activities throughout FirstEnergy. The Risk Policy 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 practice. FirstEnergy also uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.
FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value unless they meet the normal purchases and normal sales criteria. Derivatives that meet those criteria are accounted for under the accrual method of accounting, and their effects are included in earnings at the time of contract performance. Changes in the fair value of derivative instruments that qualified and were designated as cash flow hedge instruments are recorded in AOCI. Changes in the fair value of derivative instruments that are not designated as cash flow hedge instruments are recorded in net income on a mark-to-market basis. FirstEnergy has contractual derivative agreements through December 2018.
Cash Flow Hedges
FirstEnergy has used cash flow hedges for risk management purposes to manage the volatility related to exposures associated with fluctuating interest rates and commodity prices. The effective portion of gains and losses on a derivative contract are reported as a component of AOCI with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects earnings.
As of December 31, 2010, commodity derivative contracts designated in cash flow hedging relationships were $104 million of assets and $101 million of liabilities. In February 2011, FirstEnergy elected to dedesignate all outstanding cash flow hedge relationships. Total net unamortized gains included in AOCI associated with dedesignated cash flow hedges totaled $19 million as of December 31, 2011. Since the forecasted transactions remain probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments. Reclassifications from AOCI into other operating expenses were $26 million for the year ended December 31, 2011. Approximately $9 million is expected to be amortized to income during the next twelve months.
FirstEnergy has 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 were 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. As of December 31, 2011, no forward starting swap agreements were outstanding. Total unamortized losses included in AOCI associated with prior interest rate cash flow hedges totaled $79 million as of December 31, 2011. Based on current estimates, approximately $9 million will be amortized to interest expense during the next twelve months. Reclassifications from AOCI into interest expense totaled $12 million and $11 million during 2011 and 2010, respectively.
Fair Value Hedges
FirstEnergy has used fixed-for-floating interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with the debt portfolios of its subsidiaries. These derivative instruments were 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. As of December 31, 2011, no fixed-for-floating interest rate swap agreements were outstanding.
Unamortized gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements totaled $102 million as of December 31, 2011. Based on current estimates, approximately $22 million will be amortized to interest expense during the next twelve months. Reclassifications from long-term debt into interest expense totaled approximately $22 million and $12 million during 2011 and 2010, respectively.
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 where the hedging relationship does not qualify for hedge accounting.
Electricity forwards are used to balance expected sales with expected generation and purchased power. Natural gas futures are entered into based on expected consumption of natural gas at 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.
As of December 31, 2011, FirstEnergy’s net asset position under commodity derivative contracts was $17 million. Under these commodity derivative contracts, FES posted $52 million and AE Supply posted $1 million in collateral. Certain commodity derivative contracts include credit risk-related contingent features that would require FES to post $28 million and AE Supply to post $2 million of additional collateral if the credit rating for its debt were to fall below investment grade.


225


Based on commodity derivative contracts held as of December 31, 2011, an adverse 10% change in commodity prices would decrease net income by approximately $13 million during the next twelve months.
FTRs
FirstEnergy holds FTRs that generally represent an economic hedge of future congestion charges that will be incurred in connection with FirstEnergy’s load obligations. FirstEnergy acquires the majority of its FTRs in an annual auction through a self-scheduling process involving the use of ARRs allocated to members of an RTO that have load serving obligations and through the direct allocation of consolidated tax liabilities. Net tax benefits attributable to FirstEnergy, excluding any tax benefits derived from interest expense associated with acquisition indebtednessFTRs from the mergerPJM RTO. The PJM RTO has a rule that allows directly allocated FTRs to be granted to LSEs in zones that have newly entered PJM. For the first two planning years (June 1, 2011, through May 31, 2013, for the Ohio Companies), PJM permits the LSEs to request a direct allocation of FTRs in these new zones at no cost as opposed to receiving ARRs. The directly allocated FTRs differ from traditional FTRs in that the ownership of all or part of the FTRs may shift to another LSE if customers choose to shop with GPU,the other LSE.
The future obligations for the FTRs acquired at auction are reallocatedreflected on FirstEnergy's Consolidated Balance Sheets and have not been designated as cash flow hedge instruments. FirstEnergy initially records these FTRs at the auction price less the obligation due to the RTO, and subsequently adjusts the carrying value of remaining FTRs to their estimated fair value at the end of each fiscal quarter prior to settlement. Changes in the fair value of FTRs held by FirstEnergy’s unregulated subsidiaries of FirstEnergy that have taxable income. That allocation isare included in other operating expenses as unrealized gains or losses. Unrealized gains or losses on FTRs held by FirstEnergy’s regulated subsidiaries are recorded as regulatory assets or liabilities. Directly allocated FTRs are accounted for as a capital contribution tounder the company receivingaccrual method of accounting, and their effects are included in earnings at the tax benefit.time of contract performance.

212

The following tables provide a reconciliationsummarize the fair value of federal income tax expense at the federal statutory rate to the total provision for income taxes for the three years ended December 31, 2009.

  FE  FES  OE  CEI  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
2009                        
Book income before provision for income taxes $1,251  $892  $188  $(23) $32  $279  $84  $111 
Federal income tax expense at statutory rate $438  $312  $66  $(8) $11  $98  $29  $39 
Increases (reductions) in taxes resulting from-                                
Amortization of investment tax credits  (9)  (4)  (2)  (1)  -   -   -   (1)
State income taxes, net of federal tax benefit  56   21   5   2   1   18   2   5 
Manufacturing deduction  (13)  (11)  (2)  1   (1)  -   -   - 
Effectively settled tax items  (217)  -   -   -   -   -   -   - 
Other, net  (10)  (3)  (1)  (4)  (3)  (7)  (2)  3 
Total provision for income taxes $245  $315  $66  $(10) $8  $109  $29  $46 
                                 
2008                                
Book income before provision for income taxes $2,119  $800  $310  $421  $105  $335  $149  $146 
Federal income tax expense at statutory rate $742  $280  $109  $147  $37  $117  $52  $51 
Increases (reductions) in taxes resulting from-                                
Amortization of investment tax credits  (13)  (4)  (4)  (2)  -   -   (1)  (1)
State income taxes, net of federal tax benefit  60   21   1   2   (2)  25   7   5 
Manufacturing deduction  (29)  (16)  (3)  (8)  (2)  -   -   - 
Effectively settled tax items  (14)  -   -   -   -   -   -   - 
Other, net  31   12   (4)  (2)  (3)  6   3   3 
Total provision for income taxes $777  $293  $99  $137  $30  $148  $61  $58 
                                 
2007                                
Book income before provision for income taxes $2,192  $833  $298  $440  $145  $335  $164  $157 
Federal income tax expense at statutory rate $767  $292  $104  $154  $51  $117  $57  $55 
Increases (reductions) in taxes resulting from-                                
Amortization of investment tax credits  (14)  (4)  (4)  (2)  (1)  (1)  (1)  - 
State income taxes, net of federal tax benefit  110   45   -   14   6   24   9   8 
Manufacturing deduction  (9)  (6)  (2)  (1)  -   -   -   - 
Other, net  29   (22)  3   (2)  (2)  9   3   1 
Total provision for income taxes $883  $305  $101  $163  $54  $149  $68  $64 

213

Accumulated deferred income taxes as of December 31, 2009 and 2008 are as follows:

  FE  FES  OE  CEI  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
                         
AS OF DECEMBER 31, 2009                        
Property basis differences $3,049  $619  $508  $419  $177  $458  $275  $350 
Regulatory transition charge  334   -   67   95   2   157   13   - 
Customer receivables for future income taxes  111   -   -   -   -   13   49   49 
Deferred customer shopping incentive  55   -   -   55   -   -   -   - 
Deferred MISO/PJM transmission costs  89   -   -   -   -   -   90   (1)
Other regulatory assets - RCP  162   -   80   54   28           - 
Deferred sale and leaseback gain  (486)  (426)  (40)  -   -   (9)  (11)  - 
Nonutility generation costs  9   -   -   -   -   -   48   (39)
Unamortized investment tax credits  (48)  (22)  (4)  (4)  (2)  (2)  (5)  (4)
Unrealized losses on derivative hedges  (44)  (8)  -   -   -   (1)  (1)  - 
Pension and other postretirement obligations  (611)  (75)  (57)  (18)  (34)  (72)  (20)  (83)
Lease market valuation liability  (232)  (101)  -   -   (111)  -   -   - 
Oyster Creek securitization (Note 12(C))  132   -   -   -   -   132   -   - 
Nuclear decommissioning activities  (34)  23   5   -   12   (19)  (1)  (52)
Mark-to-market adjustments  (76)  (76)  -   -   -   -   -   - 
Deferred gain for asset sales -affiliated companies  -   -   37   25   8   -   -   - 
Allowance for equity funds used used during construction  15   -   15   -   -   -   -   - 
Loss carryforwards  (33)  -   -   -   -   -   -   - 
Loss carryforward valuation reserve  21   -   -   -   -   -   -   - 
All other  55   (21)  49   19   1   31   16   22 
Net deferred income tax liability (asset) $2,468  $(87) $660  $645  $81  $688  $453  $242 
                                 
AS OF DECEMBER 31, 2008                                
Property basis differences $2,736  $434  $494  $428  $172  $436  $275  $329 
Regulatory transition charge  292   -   40   29   4   190   29   - 
Customer receivables for future income taxes  145   -   22   1   -   24   49   48 
Deferred customer shopping incentive  151   -   -   151   -   -   -   - 
Deferred MISO/PJM transmission costs  167   -   11   7   7   -   137   4 
Other regulatory assets - RCP  253   -   121   100   32   -   -   - 
Deferred sale and leaseback gain  (505)  (438)  (45)  -   -   (10)  (12)  - 
Nonutility generation costs  (52)  -   -   -   -   -   30   (82)
Unamortized investment tax credits  (51)  (23)  (5)  (5)  (2)  (2)  (6)  (5)
Unrealized losses on derivative hedges  (68)  (15)  -   -   -   (1)  (1)  - 
Pension and other postretirement obligations  (715)  (68)  (94)  (47)  (25)  (90)  (72)  (89)
Lease market valuation liability  (254)  (124)  -   -   (122)  -   -   - 
Oyster Creek securitization (Note 12(C))  137   -   -   -   -   137   -   - 
Nuclear decommissioning activities  (130)  14   2   -   13   (34)  (65)  (55)
Deferred gain for asset sales -affiliated companies  -   -   41   27   9   -   -   - 
Allowance for equity funds used during construction  21   -   20   1   -   -   -   - 
Loss carryforwards  (35)  -   -   -   -   -   -   - 
Loss carryforward valuation reserve  27   -   -   -   -   -   -   - 
All other  44   (48)  46   12   (9)  39   24   20 
Net deferred income tax liability (asset) $2,163  $(268) $653  $704  $79  $689  $388  $170 

214

Upon reaching a settlement on several items under appeal for the tax years 2001-2003, as well as other items that effectively settled in 2009, FirstEnergy recognized approximately $100 million of net tax benefits, including $161 million that favorably affected FirstEnergy’s effective tax rate. The offsetting $61 million primarily related to tax items where the uncertainty was removed and the tax refund will be received when the tax years are closed. Upon completion of the federal tax examinations for tax years 2004-2006, as well as other tax settlements reached in 2008, FirstEnergy recognized approximately $42 million of net tax benefits, including $7 million that favorably affected FirstEnergy’s effective tax rate. The remaining balance of the tax benefits recognized in 2008 adjusted goodwill as a purchase price adjustment ($20 million) and accumulated deferred income taxes for temporary tax items ($15 million). During 2007, there were no material changes to FirstEnergy’s unrecognized tax benefits.

As of December 31, 2009, it is reasonably possible that approximately $148 million of the unrecognized benefits may be resolved within the next twelve months, of which up to approximately $11 million, if recognized, would affect FirstEnergy’s effective tax rate. The potential decrease in the amount of unrecognized tax benefits is primarily associated with issues related to the capitalization of certain costs and various state tax items.

In 2008, FirstEnergy, on behalf of FGCO and NGC, filed a change in accounting method related to the costs to repair and maintain electric generation stations. During the second quarter of 2009, the IRS approved the change in accounting method and $281 million of costs were included as a repair deductionderivative instruments on 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 year.Consolidated Balance Sheets:

In 2009, FirstEnergy, on behalf of OE, PP, CEI, TE, ATSI, JCP&L, Met-Ed and Penelec, filed a change in accounting method related to the costs to repair and maintain electric utility network (transmission and distribution) assets and is in the process of computing the amount of costs that will qualify as a deduction to be included on FirstEnergy’s 2009 consolidated tax return. This change in accounting method is expected to have a material impact on taxable income for 2009 and could increase the amount of tax refunds to be recognized in 2010 with a corresponding adjustment to accumulated deferred income taxes for this temporary tax item. There would be no impact on FirstEnergy’s effective tax rate.

The changes in unrecognized tax benefits for the three years ended December 31, 2009 are as follows:

  FE  FES  OE  CEI  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
Balance as of January 1, 2009
 $219  $5  $(30) $(26) $(4) $42  $28  $24 
Increase for tax positions related to the current year
  41   34   4   3   -   -   -   - 
Increase for tax positions related to prior years
  46   2   103   52   10   -   -   - 
Decrease for tax positions related to prior years
  (100)  -   -   -   -   (28)  (15)  (13)
Decrease for settlement
  (15)  -   -   -   -   -   -   - 
Balance as of December 31, 2009
 $191  $41  $77  $29  $6  $14  $13  $11 

  FE  FES  OE  CEI  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
Balance as of January 1, 2008
 $272  $14  $(12) $(17) $(1) $38  $24  $16 
Increase for tax positions related to the current year
  14   -   1   -   -   -   -   - 
Increase for tax positions related to prior years
  -   1   1   -   -   6   5   9 
Decrease for tax positions related to prior years
  (56)  (10)  (14)  (8)  (3)  (2)  (1)  (1)
Decrease for settlement
  (11)  -   (6)  (1)  -   -   -   - 
Balance as of December 31, 2008
 $219  $5  $(30) $(26) $(4) $42  $28  $24 

  FE  FES  OE  CEI  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
Balance as of January 1, 2007
 $268  $14  $(19) $(15) $(3) $44  $18  $20 
Increase for tax positions related to the current year
  1   -   1   -   -   -   -   - 
Increase for tax positions related to prior years
  3   4   10   2   2   -   6   - 
Decrease for tax positions related to prior years
  -   (4)  (4)  (4)  -   (6)  -   (4)
Balance as of December 31, 2007
 $272  $14  $(12) $(17) $(1) $38  $24  $16 

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Derivatives not designated as hedging instruments:
Derivative Assets Derivative Liabilities
 Fair Value  Fair Value
 December 31,
2011		 December 31,
2010		  December 31,
2011		 December 31,
2010
 (In millions)  (In millions)
Power Contracts    Power Contracts   
Current Assets$185
 $96
 Current Liabilities$(196) $(209)
Noncurrent Assets79
 40
 Noncurrent Liabilities(51) (38)
FTRs    FTRs   
Current Assets1
 —
 Current Liabilities(22) —
Noncurrent Assets—
 —
 Noncurrent Liabilities(1) —
NUGs56
 122
 NUGs(349) (467)
Interest Rate Swaps
   Interest Rate Swaps   
Current Assets—
 —
 Current Liabilities—
 —
Noncurrent Assets—
 —
 Noncurrent Liabilities—
 —
Other    Other   
Current Assets—
 10
 Current Liabilities—
 —
Noncurrent Assets—
 —
 Noncurrent Liabilities—
 —
Total Derivatives Assets$321
 $268
 Total Derivatives Liabilities$(619) $(714)

FirstEnergy 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 $161 million in recognized tax benefits favorably affected FirstEnergy's effective tax rate in 2009 by $56 million and an interest receivable of $11 million was removed from the accrued interest for uncertain tax positions. The reversal of accrued interest associated with the $56 million in recognized tax benefits favorably affected FirstEnergy’s effective tax rate in 2008 by $12 million and an interest receivable of $4 million was removed from the accrued interest for uncertain tax positions. During the years ended December 31, 2009, 2008 and 2007, FirstEnergy recognized net interest expense (income) of approximately $(49) million, $2 million and $19 million, respectively. The net amount of interest accrued as of December 31, 2009 and 2008 was $21 million and $59 million, respectively.

The following table summarizes the net interest expense (income)volumes associated with FirstEnergy’s outstanding derivative transactions as of December 31, 2011:
 Purchases Sales Net
 (In thousands of MWH)
Power Contracts32,188
 49,737
 (17,549)
FTRs32,534
 —
 32,534
NUGs23,981
 —
 23,981


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The following tables summarize the effect of derivative instruments on the Consolidated Statements of Income during 2011 and 2010:
 Power Contracts FTRs Other Total
 (In millions)
Derivatives in a Hedging Relationship       
December 31, 2011       
Gain Recognized in AOCI (Effective Portion)$11
 $—
 $1
 $12
Effective Gain (Loss) Reclassified to:(1)
       
Purchased Power Expense16
 —
 —
 16
Revenues(12) —
 —
 (12)
December 31, 2010       
Gain Recognized in AOCI (Effective Portion)$12
 $—
 $11
 $23
Effective Loss Reclassified to:(1)
       
Purchased Power Expense(7) —
 —
 (7)
Revenues(4) —
 —
 (4)
Fuel Expense—
 —
 (14) (14)
        
Derivatives Not in a Hedging Relationship       
December 31, 2011       
Unrealized Gain (Loss) Recognized in:       
Purchased Power Expense$120
 $—
 $—
 $120
Revenues(3) —
 —
 (3)
Other Operating Expense(52) (14) 2
 (64)
Realized Gain (Loss) Reclassified to:       
Purchased Power Expense(159) —
 —
 (159)
Revenues17
 67
 —
 84
Other Operating Expense—
 (157) —
 (157)
December 31, 2010       
Unrealized Gain Recognized in:       
Purchased Power Expense$86
 $—
 $—
 $86
Realized Loss Reclassified to:       
Purchased Power Expense(104) —
 —
 (104)
Derivatives Not in a Hedging Relationship Generally Subject to Regulatory Offset(2)
 NUGs Other Total
  (In millions)
December 31, 2011      
Unrealized Loss to Derivative Instrument $(202) $(5) $(207)
Unrealized Gain to Regulatory Assets 202
 5
 207
Realized Gain (Loss) to Derivative Instrument 254
 (13) 241
Realized Gain (Loss) to Regulatory Assets (254) 13
 (241)
December 31, 2010      
Unrealized Loss to Derivative Instrument $(181) —
 $(181)
Unrealized Gain to Regulatory Assets 181
 —
 181
Realized Gain (Loss) to Derivative Instrument 280
 (9) 271
Realized Gain (Loss) to Regulatory Assets (280) 9
 (271)
(1)
The ineffective portion was immaterial.
(2)
Changes in the fair value of certain contracts are deferred for future recovery from (or refund to) customers.


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The following table provides a reconciliation of changes in the fair value of certain contracts that are deferred for future recovery from (or credit to) customers during 2011 and 2010:
Derivatives Not in a Hedging Relationship Generally Subject to Regulatory Offset NUGs Other Total
  (In millions)
Outstanding net asset (liability) as of January 1, 2010 $(444) $19
 $(425)
Additions/Change in value of existing contracts (181) —
 (181)
Settled contracts 280
 (9) 271
Outstanding net asset (liability) as of December 31, 2010 (345) 10
 (335)
Additions/Change in value of existing contracts (202) (5) (207)
Settled contracts 254
 (13) 241
Outstanding net asset (liability) as of December 31, 2011 $(293) $(8) $(301)
11. IMPAIRMENT OF LONG-LIVED ASSETS
FirstEnergy reviews long-lived assets, including regulatory assets, for impairment whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The recoverability of a long-lived asset is measured by comparing its carrying value to the sum of undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is greater than the undiscounted cash flows, impairment exists and a loss is recognized by FES and the Utilities for the three years ended December 31, 2009amount by which the carrying value of the long-lived asset exceeds its estimated fair value.
Fremont Energy Center
On March 11, 2011, FirstEnergy and the cumulative net interest payable (receivable) as of December 31, 2009 and 2008:

 Net Interest Expense (Income) Net Interest Payable 
 For the Years Ended (Receivable) 
 December 31, As of December 31, 
 2009 2008 2007 2009 2008 
 (In millions) (In millions) 
FES
 $(1) $-  $-  $2  $1 
OE
  4   (4)  1   9   (9)
CEI
  3   (2)  (1)  3   (7)
TE
  -   -   -   1   (1)
JCP&L
  (4)  1   1   1   11 
Met-Ed
  (2)  1   2   1   6 
Penelec
  (1)  2   -   1   6 
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 returnsAmerican Municipal Power, Inc., entered into an agreement for the years 2001-2003 in July 2004sale of Fremont Energy Center, which included two natural gas combined-cycle combustion turbines and several items were under appeal. Ina steam turbine capable of producing 544 MW of load-following capacity and 163 MW of peaking capacity. The execution of this agreement triggered a need to evaluate the fourth quarterrecoverability of 2009, these items were settled at appeals and sent to Joint Committeethe carrying value of the assets associated with the Fremont Energy Center. The estimated fair value of the Fremont Energy Center was based on Taxation for final review. The federal audits for years 2004-2006 were completedthe purchase price outlined in the third quartersale agreement with American Municipal Power, Inc. The result of 2008 and several items are under appeal. The IRS began auditingthis evaluation indicated that the year 2007 in February 2007 under its Compliance Assurance Process program andcarrying cost of the Fremont Energy Center was completednot fully recoverable. As a result of the recoverability evaluation, FirstEnergy recorded an impairment charge of $11 million to operating income in the first quarter of 2009 with two items under appeal.2011. On July 28, 2011, FirstEnergy completed the sale of Fremont Energy Center to American Municipal Power, Inc.
Peaking Facilities
During 2011, FirstEnergy assessed the carrying values of certain peaking facilities that were more likely than not to be sold or disposed of before the end of their useful lives. The IRS began auditingestimated fair values were based on estimated sales prices quoted in an active market. The result of the year 2008 in evaluation indicated that the carrying costs of the peaking facilities were not fully recoverable. FirstEnergy recorded impairment charges of $23 million during 2011 as a result of the recoverability evaluation and on October 18, 2011, FirstEnergy closed on the sale of the Richland and Stryker peaking facilities.
Generating Plant Retirements
On January 26, 2012, FirstEnergy announced that it will retire certain coal-fired generating plants owned by FGCO or AE Supply: Bay Shore Units 2-4, Eastlake Units 1-5, Ashtabula, Lake Shore, Armstrong Units 1-2 and R. Paul Smith Units 3-4. On February 20088, 2012, FirstEnergy announced that it will retire three additional coal-fired generation plants owned by MP: Albright, Willow Island and the audit is expected to close before December 2010. The 2009 tax year audit began in February 2009 and is not expected to close before December 2010. Management believes that adequate reserves have been recognized and final settlementRivesville. All of these audits is not expected to have a material adverse effect on FirstEnergy’s financial condition or results of operations.

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1, representing 779 MW of net demonstrated capacity (see Note 7). This transaction generated tax capital gains of approximately $815 million, all of which were offset by existing tax capital loss carryforwards. Accordingly, FirstEnergy reduced its tax loss carryforward valuation allowance in the third quarter of 2007, with a corresponding reduction to goodwill (see Note 2(E)).

FirstEnergy has pre-tax net operating loss carryforwards for state and local income tax purposes of approximately $1.044 billion, of which $194 million isgenerating plants are expected to be utilized. The associated deferred tax assetsclosed by September 1, 2012 and are $11 million. These losses expire as follows:

Expiration Period
  FE  FES  Penelec 
   (In millions) 
2010-2014  $226  $16  $- 
2015-2019   8   -   - 
2020-2024   523   23   200 
2025-2028   287   65   - 
   $1,044  $104  $200 

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General Taxes

Details of general taxessubject to review by PJM for the three years ended December 31, 2009 are shown below:
  FE  FES  OE  CEI  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
2009                        
Kilowatt-hour excise(1)
 $224  $1  $84  $66  $24  $49  $-  $- 
State gross receipts  171   14   15   -   -   -   78   63 
Real and personal property  253   53   64   74   21   5   2   2 
Social security and unemployment  90   14   8   5   3   9   5   6 
Other  15   5   -   -   -   -   3   3 
Total general taxes $753  $87  $171  $145  $48  $63  $88  $74 
                                 
2008                                
Kilowatt-hour excise $249  $1  $97  $70  $30  $51  $-  $- 
State gross receipts  183   16   17   -   -   -   79   70 
Real and personal property  240   53   61   67   19   5   3   2 
Social security and unemployment  95   14   9   6   3   10   5   6 
Other  11   4   2   -   -   1   (1)  2 
Total general taxes $778  $88  $186  $143  $52  $67  $86  $80 
                                 
2007                                
Kilowatt-hour excise $250  $1  $99  $69  $29  $52  $-  $- 
State gross receipts  175   18   17   -   -   -   73   66 
Real and personal property  237   53   59   65   19   5   2   2 
Social security and unemployment  87   14   8   6   3   9   5   5 
Other  5   1   (2)  2   -   -   -   3 
Total general taxes $754  $87  $181  $142  $51  $66  $80  $76 
(1)Kilowatt-hour excise tax for OE and TE includes a $7.1 million and $3.5 million adjustment, respectively, recognized in 2009 related to prior periods.
11.REGULATORY MATTERS

(A)RELIABILITY INITIATIVES

In 2005, Congress amended the FPA to provide for federally-enforceable mandatory reliability standards. The mandatory reliability standards apply to the bulk power systemimpacts (see Note 16, Commitment, Guarantees and impose certain operating, record-keeping and reporting requirements on the Utilities and ATSI. The NERC is charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of its responsibilities to eight regional entities, including ReliabilityFirst Corporation. All of FirstEnergy’s facilities are located within the ReliabilityFirst region. FirstEnergy actively participates in the NERC and ReliabilityFirst stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcementContingencies, regarding PJM's review of the reliability standards.

FirstEnergy believes that itCompany's plans). The decision to close the plants is the result of a comprehensive review of FirstEnergy's coal-fired generating facilities in compliance with all currently-effective and enforceable reliability standards. Nevertheless, it is clear that the NERC, ReliabilityFirst and the FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with new or amended standards cannot be determined at this time. However, the 2005 amendments to the FPA 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 that 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 Midwest ISO 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 .  Our MISO facilities are next due for the periodic audit by ReliabilityFirst later this year.

217

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

On June 5, 2009, FirstEnergy self-reported to ReliabilityFirst a potential violation of NERC Standard PRC-005 resulting from its inability to validate maintenance records for 20 protection system relays (out of approcimately 20,000 reportable relays) in JCP&L’s and Penelec’s transmission systems. These potential violations were discovered during a comprehensive field review of all FirstEnergy substations to verify equipment and maintenance database accuracy. FirstEnergy has completed all mitigation actions, including calibrations and maintenance records for the relays. ReliabilityFirst issued an Initial Notice of Alleged Violation on June 22, 2009. The NERC approved FirstEnergy’s mitigation plan on August 19, 2009, and submitted it to the FERC for approval on August 19, 2009. FirstEnergy is not able at this time to predict what actions or penalties, if any, that ReliabilityFirst will propose for this self-reported violation.

(B)OHIO

On June 7, 2007, the Ohio Companies filed an application for an increase in electric distribution rates with the PUCO and, on August 6, 2007, updated their filing. On January 21, 2009, the PUCO granted the Ohio Companies’ application in part 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. The PUCO has not yet issued a substantive Entry on Rehearing.  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.

218

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 regulatory asset, and that the Ohio Companies would collect a delivery service improvement rider at an overall average rate of $.002 per KWH for the period of April 1, 2009 through December 31, 2011. The Amended ESP also addressed a number of other issues, including but not limited to, rate design for various customer classes, and resolution of the prudence review and the collection of deferred costsMATS rules that were approved in prior proceedings. On February 26, 2009, the Ohio Companies filed a Supplemental Stipulation, which was signed or not opposed by virtually all of the parties to the proceeding, that supplementedrecently finalized and modified certain provisions of the February 19, 2009 Stipulation and Recommendation. Specifically, the Supplemental Stipulation modified the provision relating to governmental aggregation and the Generation Service Uncollectible Rider, provided further detail on the allocation of the economic development funding contained in the Stipulation and Recommendation, and proposed additional provisions related to the collaborative process for the development of energy efficiency programs, among other provisions. The PUCO adopted and approved certain aspects of the Stipulation and Recommendation on March 4, 2009, and adopted and approved the remainder of the Stipulation and Recommendation and Supplemental Stipulation without modification on March 25, 2009. Certain aspects of the Stipulation and Recommendation and Supplemental Stipulation took effect on April 1, 2009 while the remaining provisions took effect on June 1, 2009.environmental requirements.

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, four winning bidders reached separate agreements with FES with the result that FES is now responsible for providing 77% of the Ohio Companies’ total load supply.  The results of the CBP were accepted by the PUCO on May 14, 2009. FES has also separately contracted with numerous communities to provide retail generation service through governmental aggregation programs.

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

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 .75% reduction each year thereafter through 2018. The PUCO may amend these benchmarks in certain, limited circumstances, and the Ohio Companies have filed an application with the PUCO seeking such amendments. As discussed below, on January 7, 2010, the PUCO amended the 2009 energy efficiency benchmarks to zero, contingent upon the Ohio Companies meeting the revised benchmarks in a period of not more than three years.  The PUCO has not yet acted upon the application seeking a reduction of the peak demand reduction requirements. 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. 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.  The PUCO has set the matter for hearing on March 2, 2010. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers.

219

In October 2009, the PUCO issued additional Entries on Rehearing, modifying certain of its previous rules  that set out the manner in which electric utilities, including the Ohio Companies, will be required to comply with benchmarks contained in SB221 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. Applications for rehearing filed in mid-November 2009 were granted on December 9, 2009 for the sole purpose of further consideration of the matters raised in those applications.  The PUCO has not yet issued a substantive Entry on Rehearing.  The rules implementing the requirements of SB221 went into effect on December 10, 2009. The rules set out the manner in which electric utilities, including the Ohio Companies, will be required to comply with benchmarks contained in SB221 related to the employment of alternative energy resources, energy efficiency/peak demand reduction programs as well as greenhouse gas reporting requirements and carbon dioxide control planning requirements and changes to long term forecast reporting requirements. The rules severely restrict the types of renewable energy resources energy efficiency and peak reduction programs that may be included toward meeting the statutory goals, which is expected to increase the cost of compliance for the Ohio Companies' customers. As a result of the rules going into effect in December 2009, and the PUCO’s failurethis decision, FirstEnergy recorded a pre-tax impairment of $334 million to address certain energy efficiency applications submitted by the Ohio Companies throughoutcontinuing operations during the year and the PUCO’s directive to postpone the launchended 2011. This impairment consists of a PUCO-approved energy efficiency program, the Ohio Companies, on October 27, 2009, submitted an application to amend their 2009 statutory energy efficiency benchmarks to zero. On January 7, 2010, the PUCO issued an Order granting the Companies’ request to amend the energy efficiency benchmarks.

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%$311 million write down of the KWH they servecarrying value of the plant assets, approximately $5 million in 2009.  excessive SO2 emission allowances and an $18 million charge for excessive or obsolete inventory at these facilities.
In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RFPs sought renewable energy RECs, including solar RECs and RECs generated in Ohio in order to meet the Ohio Companies' alternative energy requirements set forth in SB221. 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 December 7, 2009, the Ohio Companies filed an application with the PUCO seeking a force majeure determination regarding the Ohio Companies’ compliance with the 2009 solar energy resources benchmark, and seeking a reduction in the benchmark.  The PUCO has not yet ruled on that application.

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,addition to the CBP conducted in May 2009 in that it would procure energy, capacity and certain transmission services on a slice of system basis. Enhancements to the May 2009 CBP, the MRO would include multiple bidding sessions and multiple products with different delivery periods for generation supply features which are designed to reduce potential price volatility and reduce supplier risk and encourage bidder participation. A technical conference was held on October 29, 2009. Hearings took place in December and the 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. Although the Ohio Companies requested a PUCO determination by January 18, 2010, on February 3, 2010, the PUCO announced that its determination would be delayed. Under a determination that such statutory requirements are met, the Ohio Companies would be able to implement the MRO and conduct the CBP.

(C)PENNSYLVANIA

Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations.

On 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 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 proposed a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. 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 proposes a staggered procurement schedule, which varies by customer class. On September 2, 2009, the ALJ issued a Recommended Decision (RD) approving the settlement and adopted the Met-Ed and Penelec’s positions on two reserved issues. On November 6, 2009, the PPUC entered an Order approving the settlement and finding in favor of Met-Ed and Penelec on the two reserved issues.  Generation procurement began in January 2010.

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On May 22, 2008, the PPUC approved 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 intervenors 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.  On January 28, 2010, the PPUC adopted a motion which denies the recovery of marginal transmission losses through the TSC for the period of June 1, 2007 through March 31, 2008, and instructs Met-Ed and Penelec to work with the parties and file a petition to retain any over-collection, with interest, until 2011 for the purpose of providing mitigation of future rate increases starting in 2011 for their customers.  Met-Ed and Penelec are now awaiting an order, which is expected to be consistent with the motion. If so, Met-Ed and Penelec plan to appeal such a decision to the Commonwealth Court of Pennsylvania. Although the ultimate outcome of this matter cannot be determined at this time, it is the belief of the companies that they should prevail in any such appeal and therefore expect to fully recover the approximately $170.5 million ($138.7 million for Met-Ed and $31.8 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011.

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 subject to the outcome of the proceeding related to the 2008 TSC filing described above, as requiredemission allowance impairments 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 reconciliationplant closures, FirstEnergy recorded during 2011, pre-tax impairment charges of approximately $6 million ($1 million for costs already incurred. The TSCFES and $5 million 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 billsAE Supply) for Met-Ed’s customers would increase approximately 9.4% for the period June 2009 through May 2010.

Act 129 became effective in 2008 and addresses 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 requires utilities to file with the PPUC an energy efficiency and peak load reduction 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. 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 Pennsylvania Companies filed revised EE&C Plans on September 21, 2009. In an October 28, 2009 Order, the PPUC approved in part, and rejected in part, the Pennsylvania Companies' filing. Following additional filings related to the plans, including modifications as required by the PPUC, the PPUC issued an order on January 28, 2010, approving, in part, and rejecting, in part the Pennsylvania Companies’ modified plans. The Pennsylvania Companies filed final plans and tariff revisions on February 5, 2010 consistent with the minor revisions required by the PPUC.  The PPUC must approve or reject the plans within 60 days.

Act 129 also required utilities to file by August 14, 2009 with the PPUC smart meter technology procurement and installation plan to provide for the installation of smart meter technology within 15 years. On August 14, 2009, Met-Ed, Penelec and Penn jointly filed a Smart Meter Technology Procurement and Installation Plan. Consistent with the PPUC’s rules, 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 isNOx emission allowances that were expected to be completedobsolete after 2011 and approximately $16 million ($13 million for FES and $3 million for AE Supply) for excess SO2 emission allowances in fifteen years. Met-Ed, Penelecinventory that it expects will not be consumed in the future.
In total, 634 employees will be directly affected by this decision. Existing severance benefits will apply to those that are eligible, however, the number of affected employees could be less as some are considered for open positions at other FirstEnergy facilities and Penn estimate assessment period costsother locations. In addition, a VSP will be offered to retirement-eligible affected employees who work at approximately $29.5 million, which the Pennsylvania Companies,plants being closed. Under the VSP, employees will receive an enhanced one-time lump sum severance payment in their plan, proposedexchange for agreeing to recover throughremain an automatic adjustment clause. A Technical Conference and evidentiary hearings were held in November 2009. Briefs were filed on December 11, 2009, and Reply Briefs were filed on December 31, 2009. An Initial Decision was issuedactive employee until a date determined by FirstEnergy. Normal retirement benefits are unchanged by the presiding ALJ on January 28, 2010.  The ALJ’s Initial Decision approvedVSP.
FirstEnergy estimates that the Smart Meter Plan as modifiedtotal severance benefits may be up to $25 million ($15 million - FGCO; $5 million - AE Supply; $5


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million - MP). It is also estimated that additional costs to prepare the plants for closing during 2012 will be approximately $9 million ($4 million - FGCO; $3 million - AE Supply; $2 million - MP ). FGCO, AE Supply and MP have other obligations that could be affected 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.  Exceptions are due on February 17, 2010, and Reply Exceptions are due on March 1.  The Pennsylvania Companies expect the PPUC to act on the plans in early 2010.

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Legislation addressing rate mitigation and the expiration of rate caps has been 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.

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

On March 31, 2009, Met-Ed and Penelec submitted their 5-year NUG Statement Compliance filing to the PPUC in accordance with their 1998 Restructuring Settlement. Met-Ed proposed to reduce its CTC rate for the residential class with a corresponding increase in the generation rate and the shopping credit, and Penelec proposed to reduce its CTC rate to zero for all classes with a corresponding increase in the generation rate and the shopping credit. While these changes would result in additional annual generation revenue (Met-Ed - $27 million and Penelec - $59 million), overall rates would remain unchanged. On July 30, 2009, the PPUC entered an order approving the 5-year NUG Statement, approving the reduction of the CTC, and directing Met-Ed and Penelec to file a tariff supplement implementing this change. On July 31, 2009, Met-Ed and Penelec filed tariff supplements decreasing the CTC rate in compliance with the July 30, 2009 order, and increasing the generation rate in compliance with the Pennsylvania Companies’ Restructuring Orders of 1998. On August 14, 2009, the PPUC issued Secretarial Letters approving Met-Ed and Penelec’s compliance filings.

By Tentative Order entered September 17, 2009, the PPUC provided for an additional 30-day comment period on whether “the Restructuring Settlement allows NUG over-collection for select and isolated months to be used to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists.”   In response to the Tentative Order, 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 filed comments objecting to the above accounting method utilized by Met-Ed and Penelec. Met-Ed and Penelec filed reply comments on October 26, 2009. On November 5, 2009, the PPUC issued a Secretarial Letter allowing parties to file reply comments to Met-Ed and Penelec’s reply comments by November 16, 2009, and reply comments were filed by the Office of Consumer Advocate, ARIPPA, and the Met-Ed Industrial Users Group and Penelec Industrial Customer Alliance.  Met-Ed and Penelec are awaiting further action by the PPUC.

On February 8, 2010, Penn filed with the PPUC a generation procurement plan covering the period June 1, 2011 through May 31, 2013. The 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 proposed a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. The PPUC is required to issue an order on the plan no later than November 8, 2010.

(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 December 30, 2009, the accumulated deferred cost balance totaled approximately $98 million.

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

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

·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;

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

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

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

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

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

In support of former New Jersey Governor 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 NJBPU on August 19, 2009, and implementation began in 2009. Approval for the $11 million project related to energy efficiency programs intended to complement those currently being offered was denied by the NJBPU on December 1, 2009. Implementation of the remaining projects is dependent upon resolution of regulatory issues between the NJBPU and JCP&L including recovery of the costs associated with the proposal.

On February 11, 2010, S&P downgraded the senior unsecured debt of FirstEnergy Corp. to  BB+.  As a result, pursuant to the requirements of a pre-existing NJBPU order, JCP&L filed, on February 17, 2010 a plan addressing the mitigation of any effect of the downgrade and which provided an assessment of present and future liquidity necessary to assure JCP&L’s continued payment to BGS suppliers.  The order also provides that the NJBPU should: 1) within 10 days of that filing, hold a public hearing to review the plan and consider the available options and 2) within 30 days of that filing issue an order with respect to the matter.  At this time, the public hearing has not been scheduled and FirstEnergy and JCP&L cannot determine the impact, if any, these proceedings will have on their operations.

(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. 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, with another Company, filed an additional settlement agreement with FERC to resolve their outstanding claims. FirstEnergy is actively pursuing settlement agreements with other parties to the case.  On December 8, 2009, certain parties sought a writ of mandamus from the DC Circuit Court of Appeals directing FERC to issue an order on the Initial Decision. The Court agreed to hold this matter in abeyance based upon FERC’s representation to use good faith efforts to issue a substantive ruling on the initial decision no later than May 27, 2010. If FERC fails to act, the case will be submitted for briefing in June. This matter is pending in the Court and the outcome cannot be predicted.

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PJM Transmission Rate

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

On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. On February 11, 2008, the FERC’s April 19, 2007, and January 31, 2008, orders were appealed to the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the PUCO and another party 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. The Seventh Circuit Court of Appeals issued a decision on August 6, 2009, that remanded the rate design to FERC and denied the appeal. A request for rehearing and rehearing en banc by two Companies 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. 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 comments on February 22, 2010, with other parties submitting responsive comments on April 8, 2010 and May 10, 2010.

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. 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 remaining merchant transmission cost allocation issues were the subject of a hearing at the FERC in May 2008. On November 19, 2009, FERC issued Opinion 503 agreeing that RTEP costs should be allocated on a pro-rata basis to merchant transmission companies. On December 22, 2009, a request for a rehearing of FERC’s Opinion No. 503 was made. On January 19, 2010, FERC issued a procedural order noting that FERC would address the rehearing requests in a future order.
RTO Consolidation

On August 17, 2009, FirstEnergy filed an application with the FERC requesting to consolidate its transmission assets and operations into PJM. Currently, FirstEnergy’s transmission assets and operations are divided between PJM and MISO. The consolidation would make the transmission assets that are part of ATSI, whose footprint includes the Ohio Companies and Penn, part of PJM. Most of FirstEnergy’s transmission assets in Pennsylvania and all of the transmission assets in New Jersey already operate as a part of PJM. Key elements of the filing include a “Fixed Resource Requirement Plan” (FRR Plan) that describes the means whereby capacity will be procured and administered as necessary to satisfy the PJM capacity requirements for the 2011-12 and 2012-13 delivery years; and also a request that ATSI’s transmission customers be excused from the costs for regional transmission projects that were approved through PJM’s RTEP process prior to ATSI’s entry into PJM (legacy RTEP costs). Subject to satisfactory outcomes in the FERC dockets, 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 the Ohio Companies. 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 exempting the ATSI footprint from the legacy RTEP costs.

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.

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On December 17, 2009, FERC issued an order approving, subject to certain future compliance filings, ATSI’s move to PJM. FirstEnergy’s request to be exempted from legacy RTEP costs was rejected and its complaint dismissed.

On December 17, 2009, ATSI executed the PJM Consolidated Transmission Owners Agreement. On December 18, 2009, 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 moving into PJM on the schedule approved in the FERC Order.

On January 15, 2010, the Ohio Companies and Penn submitted a compliance filing describing the process whereby ATSI-zone load serving entities (LSEs) can “opt out” of the Ohio Companies' and Penn's proposed capacity plan for the 2011-12 and 2012-13 delivery years. On January 16, 2010, FirstEnergy filed for clarification or rehearing of certain issues associated with implementing the FRR auctions on the proposed schedule. On January 19, 2010, FirstEnergy filed for rehearing of FERC’s decision to impose the legacy RTEP costs on ATSI’s transmission customers. Also on January 19, 2010, several parties, including the PUCO and the OCC asked for rehearing of parts of FERC’s order. None of the rehearing parties asked FERC to rescind authorization for ATSI to enter PJM. Instead, parties focused on questions of cost and cost allocation or on alleged errors in implementing the move. On February 3, 2010, FirstEnergy filed an answer to the January 19, 2010, rehearing requests of other parties. On February 16, 2010, FirstEnergy submitted a second compliance filing to FERC; the filing describes communications protocols and performance deficiency penalties for capacity suppliers that are taken in FRR auctions.

FirstEnergy will conduct FRR auctions on March 15-19, 2010, for the 2011-12 and 2012-13 delivery years, and will participate in PJM’s next base residual auction for capacity resources for the 2013-2014 delivery years.  FirstEnergy expects to integrate into PJM effective June 1, 2011.

Changes ordered for PJM Reliability Pricing Model (RPM) Auction

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

On March 26, 2009, the FERC accepted in part, and rejected in part, tariff provisions submitted by PJM, revising certain parts of its RPM. It ordered changes included making incremental improvements to RPM and 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; 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,plant closings and are effective November 1, 2009. The CMEC continuescurrently unable to work to address additional compliance items directed by the March 26, 2009 Order. On December 1, 2009, PJM informed FERCreasonably estimate potential costs, or a range thereof, that PJM would file a scarcity-pricing design with FERC on April 1, 2010.could be incurred.
12. CAPITALIZATION

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. The FERC conditionally approved MISO’s Resource Adequacy proposal on March 26, 2008. 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 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 program was implemented as planned and became effective on June 1, 2009, the beginning of the MISO planning year. On June 17, 2009, MISO submitted a compliance filing in response to the FERC’s April 16, 2009 order directing it to address, among others, various market monitoring and mitigation issues. On July 8, 2009, various parties submitted comments on and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific aspects of the MISO’s and Independent Market Monitor’s proposals for market monitoring and mitigation and other issues that it believes the FERC should address and clarify. On October 23, 2009, FERC issued an order approving a MISO compliance filing that revised its tariff to provide for netting of demand resources, but prohibiting the netting of behind-the-meter generation.

FES Sales to Affiliates

FES supplied all of the power requirements for the Ohio Companies pursuant to a Power Supply Agreement that ended on December 31, 2008. On January 2, 2009, FES signed an agreement to provide 75% of the Ohio Companies’ power requirements for the period January 5, 2009 through March 31, 2009. Subsequently, FES signed an agreement to provide 100% of the Ohio Companies’ power requirements for the period April 1, 2009 through May 31, 2009. On March 4, 2009, the PUCO issued an order approving these two affiliate sales agreements. FERC authorization for these affiliate sales was by means of a December 23, 2008 waiver of restrictions on affiliate sales without prior approval of the FERC. Rehearing was denied on July 31, 2009. On October 19, 2009, FERC accepted FirstEnergy’s revised tariffs.

On May 13-14, 2009, FES participated in a descending clock auction for PLR service administered by the Ohio Companies and their consultant, CRA International. FES won 51 tranches in the auction, and entered into a Master SSO Supply Agreement to provide capacity, energy, ancillary services and transmission to the Ohio Companies for a two-year period beginning June 1, 2009.  Other winning suppliers have assigned their Master SSO Supply Agreements to FES, five of which were effective in June, two more in July, four more in August and ten more in September, 2009.  FES also supplies power used by Constellation to serve an additional five tranches.  As a result of these arrangements, FES serves 77 tranches, or 77% of the PLR load of the Ohio Companies.

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 (PRA) continues to limit the amount of capacity resources required to be supplied by FES to 3,544 MW, but requires FES to supply essentially all of Met-Ed, Penelec, and Waverly’s energy requirements in 2010. Under the Fourth Restated Partial Requirements Agreement, Met-Ed, Penelec, and Waverly (Buyers) assigned 1,300 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 under the Fourth Restated Partial Requirements Agreement 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, respectively, 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.

12.CAPITALIZATION

(A)COMMON STOCK

Retained Earnings and Dividends

As of December 31, 2009, FirstEnergy's2011, FirstEnergy’s unrestricted retained earnings were $4.5 billion.$3.0 billion. Dividends declared in 20092011 were $2.20,$2.20 per share, which included four quarterlyincludes dividends of $0.55$0.55 per share paid in the second, third and fourth quarters of 20092011 and dividends of $0.55 per share payable in the first quarter of 2010.2012. Dividends declared in 20082010 were $2.20,$2.20 per share, which included four quarterlyincludes dividends of $0.55$0.55 per share paid in the second, third and fourth quartersquarter of 20082010 and dividends of $0.55 per share paid in the first quarter of 2009.2011. The amount and timing of all dividend declarations are subject to the discretion of the Board of Directors and its consideration of business conditions, results of operations, financial condition and other factors.

226

In addition to paying dividends from retained earnings, each of FirstEnergy’s electric utility subsidiaries hasOE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec have authorization from the FERC to pay cash dividends to FirstEnergy from paid-in capital accounts, as long as itstheir equity to total capitalization ratio (without consideration of retained earnings) remains above 35%. In addition, TrAIL and AGC have authorization from the FERC to pay cash dividends to FE from paid-in capital accounts, as long as their equity to total capitalization ratio (without consideration of retained earnings) remains above 50% and 45%, respectively. The articles of incorporation, indentures, regulatory limitations and various other agreements relating to the long-term debt of certain FirstEnergy subsidiaries contain provisions that could further restrict the payment of dividends on their common stock. None of these provisions materially restricted FirstEnergy’s subsidiaries’ abilityabilities to pay cash dividends to FirstEnergy as of December 31, 2009.2011.

As described in Note 1, Organization Basis of Presentation and Significant Accounting Policies, FirstEnergy elected to change its method of recognizing actuarial gains and losses for its defined benefit pension plans and other postemployment benefit plans and applied this change retrospectively to all periods presented. The retrospective application of this change caused accumulated deficits for certain of the Utility Registrants during those prior periods, including periods when dividends were paid from retained earnings. Previous to this accounting change, retained earnings were sufficient for those dividends that were declared and paid.
(B)PREFERRED AND PREFERENCE STOCK

FirstEnergy’sFirstEnergy and the Utilities’Utilities were authorized to issue preferred stock and preference stock authorizations areas of December 31, 2011, as follows:

 Preferred Stock  Preference Stock 
 Shares  Par  Shares  Par  Preferred Stock Preference Stock
 Authorized  Value  Authorized  Value  Shares Authorized Par Value Shares Authorized Par Value
FirstEnergy  5,000,000  $100        5,000,000 $100 
OE  6,000,000  $100   8,000,000  no par  6,000,000 $100 8,000,000 no par
OE  8,000,000  $25         8,000,000 $25 
Penn  1,200,000  $100         1,200,000 $100 
CEI  4,000,000  no par   3,000,000  no par  4,000,000 no par 3,000,000 no par
TE  3,000,000  $100   5,000,000  $25  3,000,000 $100 5,000,000 $25
TE  12,000,000  $25          12,000,000 $25 
JCP&L  15,600,000  no par          15,600,000 no par 
Met-Ed  10,000,000  no par          10,000,000 no par 
Penelec  11,435,000  no par          11,435,000 no par 
MP 940,000 $100 
PE 10,000,000 $0.01 
WP 32,000,000 no par 

NoAs of December 31, 2011, and 2010, there were no preferred shares or preference shares are currently outstanding.


(C)229


LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS

The following table presents thetables present outstanding consolidated long-term debt and other long-termcapital lease obligations offor FirstEnergy, FES and the Utility Registrants as of December 31, 20092011 and 2008:2010:
 As of December 31, 2011 
As of December 31, 
(Dollar amounts in millions)Maturity Date Interest Rate 2011 2010
FirstEnergy:       
FMBs2012 - 2038 5.125% - 9.740% $2,487
 $1,023
Secured notes - fixed rate2012 - 2037 3.000% - 7.880% 2,725
 2,727
Secured notes - variable rate2012 0.090% 50
 57
Total secured notes    2,775
 2,784
Unsecured notes - fixed rate2012 - 2039 2.225% - 8.250% 10,961
 9,351
Unsecured notes - variable rate2012 - 2013 0.030% - 2.918% 782
 770
Total unsecured notes    11,743
 10,121
Capital lease obligations    108
 54
Unamortized debt premiums    64
 83
Unamortized merger fair value adjustments    160
 —
Currently payable long-term debt    (1,621) (1,486)
Total long-term debt and other long-term obligations    $15,716
 $12,579
        
FES:       
Secured notes - fixed rate2012 - 2018 3.000% - 7.250% $899
 $838
Secured notes - variable rate2012 0.090% 50
 434
Total secured notes    949
 1,272
Unsecured notes - fixed rate2012 - 2039 2.250% - 6.800% 2,218
 2,562
Unsecured notes - variable rate2012 0.040% - 0.090% 508
 445
Total unsecured notes    2,726
 3,007
Capital lease obligations    31
 36
Unamortized debt discounts    (2) (2)
Currently payable long-term debt    (905) (1,132)
Total long-term debt and other long-term obligations    $2,799
 $3,181
        
OE:       
FMBs2012 - 2038 8.250% $407
 $408
Unsecured notes - fixed rate2015 - 2038 5.450% - 6.875% 750
 750
Capital lease obligations    11
 7
Unamortized debt discounts    (11) (12)
Currently payable long-term debt    (2) (1)
Total long-term debt and other long-term obligations    $1,155
 $1,152
        
CEI:       
FMBs2018 - 2024 5.500% - 8.875% $600
 $600
Secured notes - fixed rate2017 7.880% 300
 300
Unsecured notes - fixed rate2013 - 2036 5.650% - 5.950% 850
 850
Unsecured notes due to affiliates2012 - 2016 7.663% 81
 103
Capital lease obligations    8
 3
Unamortized debt discounts    (3) (3)
Currently payable long-term debt    (1) —
Total long-term debt and other long-term obligations    $1,835
 $1,853
        


  Weighted Average  December 31, 
  Interest Rate (%)  2009  2008 
     (In millions) 
FMBs:         
Due 2009-2013 5.96  $28  $29 
Due 2014-2018 8.84   330   330 
Due 2019-2023 6.22   107   7 
Due 2024-2028 8.75   314   14 
Due 2038 8.25   275   275 
Total FMBs     1,054   655 
            
Secured Notes:           
Due 2009-2013 7.68   356   607 
Due 2014-2018 7.35   557   613 
Due 2019-2023 7.05   341   70 
Total Secured Notes     1,254   1,290 
            
Unsecured Notes:           
Due 2009-2013 5.50   878   2,253 
Due 2014-2018 5.56   2,693   2,149 
Due 2019-2023 5.47   2,575   689 
Due 2024-2028 4.36   65   65 
Due 2029-2033 6.18   2,247   2,247 
Due 2034-2038 4.99   2,186   1,936 
Due 2039-2043 4.70   755   255 
Due 2047 3.00   46   46 
Total Unsecured Notes     11,445   9,640 
            
Capital lease obligations     13   8 
Net unamortized discount on debt     (24)  (17)
Long-term debt due within one year     (1,834)  (2,476)
Total long-term debt and other long-term obligations    $11,908  $9,100 
230


227
 As of December 31, 2011 
As of December 31, 
(Dollar amounts in millions)Maturity Date Interest Rate 2011 2010
TE:       
Secured notes - fixed rate2020 - 2037 6.150% - 7.250% $600
 $600
Capital lease obligations    1
 3
Unamortized debt discounts    (2) (3)
Total long-term debt and other long-term obligations    $599
 $600
        
JCP&L:       
Secured notes - fixed rate2012 - 2021 5.250% - 6.160% $277
 $310
Unsecured notes - fixed rate2016 - 2037 4.800% - 7.350% 1,500
 1,500
Unamortized debt discounts    (7) (8)
Currently payable long-term debt    (34) (32)
Total long-term debt    $1,736
 $1,770
        
Met-Ed:       
FMBs
 
 $—
 $14
Unsecured notes - fixed rate2013 - 2019 4.875% - 7.700% 700
 700
Unsecured notes - variable rate2012 0.090% 29
 29
Total unsecured notes    729
 729
Capital lease obligations    4
 5
Currently payable long-term debt    (29) (29)
Total long-term debt and other long-term obligations    $704
 $719
    
Penelec:       
Unsecured notes - fixed rate2014 - 2038 5.125% - 6.625% $1,075
 $1,100
Unsecured notes - variable rate2012 0.030% - 0.090% 45
 20
Total unsecured notes    1,120
 1,120
Capital lease obligations    4
 —
Unamortized debt discounts    (2) (3)
Currently payable long-term debt    (46) (45)
Total long-term debt and other long-term obligations    $1,076
 $1,072
See Note 6, Leases for additional information related to capital leases.

Securitized Bonds
Environmental Control Bonds
The consolidated financial statements of FirstEnergy include environmental control bonds issued by two bankruptcy remote, special purpose limited liability companies that are indirect subsidiaries of MP and PE. Proceeds from the bonds were used to construct environmental control facilities. The special purpose limited liability companies own the irrevocable right to collect non-bypassable environmental control charges from all customers who receive electric delivery service in MP's and PE's West Virginia service territories. Principal and interest owed on the environmental control bonds is secured by, and payable solely from, the proceeds of the environmental control charges. The right to collect environmental control charges is not included on FirstEnergy's consolidated balance sheets. Creditors of FirstEnergy, other than the special purpose limited liability companies, have no recourse to any assets or revenues of the special purpose limited liability companies. As of December 31, 2011, $513 million of environmental control bonds were outstanding.
Transition Bonds

The consolidated financial statements of FirstEnergy and JCP&L include the accounts 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&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'sFirstEnergy’s and JCP&L's&L’s Consolidated Balance Sheets. As of December 31, 2009, $340 million ofSheets, and the transition bonds were outstanding. The transition bonds are the sole obligations


231


of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each company’s equity and assets, which consist primarily of bondable transition property. As of December 31, 2011, $287 million of the transition bonds were outstanding.

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 annual servicing fees of up to $628,000$628 thousand that are payable from TBC collections.

Other Long-term Debt

The Ohio Companies, Penn, FGCO and NGC and each of the Utilities, except for JCP&L, have a first mortgage indenture under which they can issue FMBs secured by a direct first mortgage lien on substantially all of their property and franchises, other than specifically excepted property.

FirstEnergy and its subsidiaries have various debt covenants under their respective financing arrangements. The most restrictive of the debt covenants relate to the nonpayment of interest and/or principal on debt and the maintenance of certain financial ratios. There also exist cross-default provisions in a number of the respective financing arrangements of FirstEnergy, FES, FGCO, NGC and the Utilities. These provisions generally trigger a default in the applicable financing arrangement of an entity if it or any of its significant subsidiaries defaults under another financing arrangement of a certain principal amount, typically $50 million. Although such defaults by any of the Utilities will generally cross-default FirstEnergy financing arrangements containing these provisions, defaults by FirstEnergy will not generally cross-default applicable financing arrangements of any of the Utilities. Defaults by any of FES, FGCO or NGC will generally cross-default to applicable financing arrangements of FirstEnergy and, due to the existence of guarantees by FirstEnergy of certain financing arrangements of FES, FGCO and NGC, defaults by FirstEnergy will generally cross-default FES, FGCO and NGC financing arrangements containing these provisions. Cross-default provisions are not typically found in any of the senior note or FMBs of FirstEnergy or the Utilities.

Based on the amount of FMBs authenticated by the respective mortgage bond trustees through as of December 31, 2009,2011, the Utilities’ annual sinking fund requirement for all FMBFMBs issued under the various mortgage indentures amounted to $35payments, all of which relate to Penn, was $6 million (Penn - $6 million, Met-Ed - $8 million and Penelec - $21 million) in 2011. Penn expects to meet its 20102011 annual sinking fund requirement with a replacement credit under its mortgage indenture. Met-Ed and Penelec could fulfill their sinking fund obligations by providing bondable property additions, previously retired FMBs or cash to the respective mortgage bond trustees.

As of December 31, 2009,2011, FirstEnergy’s currently payable long-term debt includes approximately $1.6 billion$632 million (FES - $1.5 billion,— $558 million, Penelec — $45 million and Met-Ed - $29— $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. Prior to the third quarter of 2008, FirstEnergy subsidiaries had not experienced any unsuccessful remarketings of these variable-rate PCRBs. Coincident with recent disruptions in the variable-rate demand bond and capital markets generally, certain of the PCRBs had been tendered by bondholders to the trustee. As of January 31, 2009, all PCRBs that had been tendered were successfully remarketed.

228

In 2009, holders of approximately $434 million of LOC-supported PCRBs of OE and NGC were notified that the applicable Wachovia Bank LOCs were set to expire. 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. FGCO remarketed $100 million of those PCRBs, which were previously held by OE and NGC and 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 needThe following table presents scheduled debt repayments for third-party credit support. Also during 2009, FGCO and NGC remarketed approximately $329 million of other PCRBs supported by LOCs set to expire in 2009. Those PCRBs were also remarketed in fixed interest rate modes and secured by FMBs, thereby eliminating the need for third-party credit support. FGCO and NGC delivered FMBs to certain LOC banks listed above in connection with amendments to existing LOC and reimbursement agreements supporting twelve other series of PCRBs as described below and pledged FMBs to the applicable trustee under six separate series of PCRBs. On August 14, 2009, $177 million of non-LOC supported fixed rate PCRBs were issued and sold on behalf of FGCO to pay a portion of the cost of acquiring, constructing and installing air quality facilities at its W.H. Sammis Generating Station.

Sinking fund requirements for FMBs and maturingoutstanding long-term debt, (excludingexcluding capital leases, fair value purchase accounting adjustments and variable rate PCRBs)unamortized debt discounts and premiums, for the next five years are:as of December 31, 2011. TE does not have any long-term debt payments due during the next five years. PCRBs that can be tendered for mandatory purchase prior to maturity are reflected in 2012.

Year FE FES OE CEI JCP&L Met-Ed Penelec  FirstEnergy FES OE CEI JCP&L Met-Ed Penelec
(In millions)  (In millions)
2010 268 52 2 18 31 100 24 
2011 337 58 1 20 32 - - 
20122012 99 68 1 22 34 - -  $1,605
 $896
 $—
 $—
 $34
 $29
 $45
20132013 557 75 2 324 36 150 -  1,314
 310
 —
 300
 36
 150
 —
20142014 531 99 1 26 38 250 150  878
 125
 —
 —
 38
 250
 150
2015 1,638
 762
 150
 —
 41
 —
 —
2016 1,050
 191
 250
 —
 343
 —
 —
The following table classifies the outstanding variable rate put bond PCRBs and variable rate PCRBs by year, excluding unamortized debt discounts and premiums, for the next threefive years representingbased on the next timedate on which the debt holders may exercise their right to tender their PCRBs. The Ohio Companies and JCP&L did not have any outstanding PCRBs as of December 31, 2011.

Year FE FES Met-Ed Penelec FirstEnergy FES Met-Ed Penelec
 (In millions) (In millions)
2010  1,568 1,494 29 45
2011  75 75 - -
2012  244 244 - - $901
 $828
 $28
 $45
2013 235
 235
 —
 —
2014 26
 26
 —
 —
2015 313
 313
 —
 —
2016 170
 170
 —
 —


Obligations to repay certain PCRBs are secured by several series of FMBs. Certain PCRBs are entitled to the benefit of irrevocable bank LOCs of $1.6 billion as of December 31, 2009, or noncancelable municipal bond insurance of $38 million as of December 31, 2009,, to pay principal of, or interest on, the applicable PCRBs. To the extent that drawings are made under the LOCs, or the insurance, FGCO, NGC and the applicable Utilities are entitled to a credit against their obligation to repay those bonds. FGCO, NGC and the applicable Utilities pay annual fees of 0.35% to 3.30% ofbased on the amounts of the LOCs to the issuing banks and are obligated to reimburse the banks or insurers, as the case may be, for any drawings thereunder. The insurers hold FMBs as security for such reimbursement obligations. These amounts and percentages for FirstEnergy, FES and the Utilities are as follows:

  FE  FES  Met-Ed  Penelec 
  (In millions) 
Amounts            
LOCs $1,568  $1,494* $29  $45 
Insurance Policies  38   -   14   24 
                 
Fees                
LOCs 0.35% to 3.30%  0.35% to 3.30%   1.5%  1.5%
*Includes LOC of $137 million issued for FirstEnergy on behalf of NGC.
In addition, OE has LOCs of $200$116 million and $134$37 million in connection with the sale and leaseback of Beaver Valley Unit 2 and Perry Unit 1, respectively. In 2004, OE entered into


232


The amounts and annual fees for PCRB-related LOCs for FirstEnergy, FGCO, NGC, Met-Ed and Penelec as of December 31, 2011, are as follows:
  Aggregate LOC Amount Annual Fees 
  (In millions)   
FGCO $365
 1.71% to 3.30% 
NGC 200
 1.71% 
Met-Ed 29
 1.75% 
Penelec 45
 1.71% to 1.75% 
  $639
   
Debt Covenant Default Provisions
FirstEnergy has various debt covenants under certain financing arrangements, including its revolving credit facilities. The most restrictive of the debt covenants relate to the nonpayment of interest and/or principal on such debt and the maintenance of certain financial ratios. The failure by FirstEnergy to comply with the covenants contained in its financing arrangements could result in an event of default, which may have an adverse effect on its financial condition.
Additionally, there are cross-default provisions in a Credit Agreement pursuantnumber of the financing arrangements. These provisions generally trigger a default in the applicable financing arrangement of an entity if it or any of its significant subsidiaries default under another financing arrangement in excess of a certain principal amount, typically $100 million. Although such defaults by any of the Utilities, ATSI or TrAIL would generally cross-default FirstEnergy financing arrangements containing these provisions, defaults by any of AE Supply, FES, FGCO or NGC would generally not cross-default to which a standby LOC was issuedapplicable financing arrangements of FirstEnergy. Also, defaults by FirstEnergy would generally not cross-default applicable financing arrangements of any of FirstEnergy’s subsidiaries. Cross-default provisions are not typically found in supportany of the senior notes or FMBs of FirstEnergy, FGCO, NGC or the Utilities.
13. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT
FirstEnergy hadnosignificant short-term borrowings as of December 31, 2011, and short-term borrowings of approximately $236$700 millionas ofDecember 31, 2010. FirstEnergy’s available liquidity as of January 31, 2012, was as follows:
Company Type Maturity Commitment Available Liquidity
      (In millions)
FirstEnergy(1)
 Revolving June 2016 $2,000
 $1,395
FES / AE Supply Revolving June 2016 2,500
 2,498
TrAIL Revolving Jan. 2013 450
 450
AGC Revolving Dec. 2013 50
 —
    Subtotal $5,000
 $4,343
    Cash —
 49
    Total $5,000
 $4,392
(1)
FE and the Utilities
Revolving Credit Facilities
FirstEnergy and FES / AE Supply Facilities
FirstEnergy and certain of its subsidiaries participate in two five-year syndicated revolving credit facilities with aggregate commitments of$4.5 billion(Facilities).
An aggregate amount of$2 billionis available to be borrowed under a syndicated revolving credit facility (FirstEnergy Facility), subject to separate borrowing sublimits for each borrower. The borrowers under the FirstEnergy Facility are FE, OE, Penn, CEI, TE, Met-Ed, ATSI, JCP&L, MP, Penelec, PE and WP. An additional$2.5 billionis available to be borrowed by FES and AE Supply under a separate syndicated revolving credit facility (FES/AE Supply Facility), subject to separate borrowing sublimits for each borrower.
Commitments under each of the Beaver Valley Unit 2Facilities will be available until June 17, 2016, unless the lenders agree, at the request of the applicable borrowers, to up to two additional one-year extensions. Generally, borrowings under each of the Facilities are available to each borrower separately and mature on the earlier of364days from the date of borrowing or the commitment termination date, as the same may be extended.


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Borrowings under each of the Facilities are subject to the usual and customary provisions for acceleration upon the occurrence of events of default, including a cross-default for other indebtedness in excess of$100 million, as described further in Note 12, Capitalization.
The following table summarizes the borrowing sub-limits for each borrower under the Facilities, 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 ofDecember 31, 2011:

Borrower Revolving Credit Facility Sub-Limit Regulatory and Other Short-Term Debt Limitations 
  (In millions) 
FE  $2,000
  —
(1) 
FES  $1,500
  —
(2) 
AE Supply  $1,000
  —
(2) 
OE  $500
  $500
 
CEI  $500
  $500
 
TE  $500
  $500
 
JCP&L  $425
  $411
(3) 
Met-Ed  $300
  $300
(3) 
Penelec  $300
  $300
(3) 
West Penn  $200
  $200
(3) 
MP  $150
  $150
(3) 
PE  $150
  $150
(3) 
ATSI  $100
  $100
 
Penn  $50
  $33
(3) 
(1)
No limitations.
(2)
No limitation based upon blanket financing authorization from the FERC under existing open market tariffs.
(3)
Excluding amounts which may be borrowed under the regulated companies’ money pool.
The entire amount of the FES/AE Supply Facility and$700 millionof the FirstEnergy Facility, subject to each borrower’s sub-limit, is available for 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 each of the Facilities and against the applicable borrower’s borrowing sub-limit.
AGC and TrAIL Revolving Credit Facilities
FirstEnergy also has established$500 millionof revolving credit facilities that are available to TrAIL ($450 million) and AGC($50 million) until January 2013 and December 2013, respectively.
FirstEnergy Money Pools
FirstEnergy’s regulated companies also have the ability to borrow from each other and the issuerholding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy’s unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the standby LOC obtainedloan, together with accrued interest, within 364 days of borrowing the right to pledge or assign participations in OE's reimbursement obligationsfunds. 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 during 2011 was0.44% per annum for the regulated companies’ money pool and0.42% per annum for the unregulated companies’ money pool.
Weighted Average Interest Rates
The weighted average interest rates on short-term borrowings outstanding, including borrowings under the credit agreement to a trust. The trust then issuedFirstEnergy Money Pools, as of December 31, 2011 and sold trust certificates to institutional investors that2010, were designed to be the credit equivalent of an investment directly in OE. In 2009, these LOCs were renewed in the amount of $145 million.as follows:


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229


13.
  2011 2010
FirstEnergy —% 0.68%
FES 0.53% 0.60%
OE —% 0.51%
CEI —% 1.92%
JCP&L 0.51% —%
Met-Ed 0.51% 0.51%
Penelec 0.51% 0.51%
14. ASSET RETIREMENT OBLIGATIONS

FirstEnergy has recognized applicable legal obligations for AROs and their associated cost primarily for nuclear power plant decommissioning, reclamation of a sludge disposal pond andponds, closure of two coal ash disposal sites.sites, underground and above-ground storage tanks, wastewater treatment lagoons and transformers containing PCBs. In addition, FirstEnergy has recognized conditional retirement obligations, (primarilyprimarily for asbestos remediation).

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 its 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 applicable Utilities use an expected cash flow approach to measure the fair value of their nuclear decommissioning AROs.

FirstEnergy, FES and thecertain Utilities maintain nuclear decommissioning trust fundsNDTs that are legally restricted for purposes of settling the nuclear decommissioning ARO. The fair values of the decommissioning trust assets as of December 31, 20092011 and 20082010 were as follows:

 2009  2008 
 (In millions) 
FE
 $1,859  $1,700 
 2011 2010
 (In millions)
FirstEnergy $2,112
 $1,973
FES
  1,089   1,034  1,223
 1,146
OE
  121   117  137
 127
TE
  74   74  83
 76
JCP&L
  167   143  193
 182
Met-Ed
  266   226  310
 289
Penelec
  143   115  166
 153
Accounting standards for conditional retirement obligations associated with tangible long-lived assets require recognition of the fair value of a liability for an ARO in the period in which it is incurred if a reasonable estimate can made, even though there may be uncertainty about timing or method of settlement. When settlement is conditional on a future event occurring, it is reflected in the measurement of the liability, not in the recognition of the liability.

The following table summarizes the changes to the ARO balances during 20092011 and 2008.2010.

ARO Reconciliation FE FES  OE  CEI  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
Balance as of January 1, 2008 $1,279 $810  $105  $2  $28  $90  $161  $82 
Liabilities incurred  5  -   -   -   -   -   -   - 
Liabilities settled  (3)  (2)  -   -   -   -   -   - 
Accretion  84  55   5   -   2   5   10   5 
Revisions in estimated cash flows  (18)1 -   (18)1  -   -   -   -   - 
Balance as of December 31, 2008  1,347  863   92   2   30   95   171   87 
                                
Liabilities incurred  4  1   -   -   -   -   -   - 
Accretion  90  58   6   -   2   7   11   6 
Revisions in estimated cash flows  (16)  (1)  (12)   -   -   -   (2)  (1)
Balance as of December 31, 2009 $1,425 $921  $86  $2  $32  $102  $180  $92 
ARO Reconciliation 
FirstEnergy(3)
 FES OE CEI TE JCP&L Met-Ed Penelec
  (In millions)
Balance, January 1, 2010 $1,425
 $921
 $86
 $2
 $32
 $102
 $180
 $92
Liabilities settled (11) —
 (10) —
 —
 —
 —
 —
Accretion 93
 59
 5
 —
 2
 6
 13
 6
Revisions in estimated cash flows(1)
 (100) (88) (7) —
 (5) —
 —
 —
Balance, December 31, 2010 1,407
 892
 74
 2
 29
 108
 193
 98
Liabilities assumed from Allegheny merger 60
 —
 —
 —
 —
 —
 —
 —
Liabilities settled(2)
 (15) (1) (2) —
 —
 —
 —
 —
Accretion 97
 59
 5
 1
 2
 7
 13
 7
Revisions in estimated cash flows(4)
 (52) (46) (6) —
 —
 —
 —
 —
Balance, December 31, 2011 $1,497
 $904
 $71
 $3
 $31
 $115
 $206
 $105
(1)OE revised
(1)
During the second quarter of 2010, studies were completed to reassess the estimated cost of decommissioning the Beaver Valley nuclear generating facilities. The cost studies resulted in a revision to the estimated cash flows associated with the retired GorgeARO liabilities and Toronto plants basedreduced the discounted liabilities as shown.


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(2)
Includes approximately $10 million in reduced ARO liabilities for FirstEnergy as a result of deconsolidation of the Signal Peak joint venture (See Note 8, Variable Interest Entities).
(3)
The 2011 changes include activity relating to Allegheny, which merged with FE in February 2011.
(4)
During 2011, studies were completed to reassess the estimated cost of decommissioning the Perry and Davis-Besse nuclear generating facilities. The cost studies resulted in revisions to the estimated cash flows associated with the ARO liabilities and reduced the discounted liabilities as shown. These revisions had no significant impact on an agreementaccretion of the obligations during 2011, as compared to remediate asbestos at the sites within one year.2010.
15. REGULATORY MATTERS

14.  SHORT-TERM BORROWINGS AND BANK LINES OF CREDITRELIABILITY MATTERS

Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES, AE Supply, FGCO, FENOC, ATSI and TrAIL. The NERC is the ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including RFC. All of FirstEnergy's facilities are located within the RFC region. FirstEnergy actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by the RFC.

FirstEnergy had approximately $1.2 billionbelieves that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of short-term indebtednessoperating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such items are found, FirstEnergy develops information about the item and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an item to RFC. Moreover, it is clear that the NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of December 31, 2009, comprisedcomplying with future new or amended standards cannot be determined at this time; however, 2005 amendments to the FPA provide that all prudent costs incurred to comply with the future reliability standards be recovered in rates. Any future inability on FirstEnergy's part to comply with the reliability standards for its bulk power system could result in the imposition of $1.1 billionfinancial penalties that could have a material adverse effect on its financial condition, results of borrowings under a $2.75 billion revolving line of credit, $100 million of other bank borrowingsoperations and $31 million of currently payable notes. Total short-term bank lines of committed credit to FirstEnergy and the Utilities as of January 31, 2010 were approximately $3.4 billion of which $1.7 billion was unused and available.cash flows.

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 resulting in customers losing power for up to eleven hours. 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. NERC has submitted first and second Requests for Information regarding this and another related matter. JCP&L is complying with these requests. JCP&L is not able to predict what actions, if any, the NERC may take with respect to this matter.

On August 23, 2010, FirstEnergy self-reported to RFC a vegetation encroachment event on a Met-Ed230kV line. This event did not result in a fault, outage, operation of protective equipment, or any other meaningful electric effect on any FirstEnergy transmission facilities or systems. On August 25, 2010, RFC issued a notice of enforcement to investigate the incident. FirstEnergy submitted a data response to RFC on September 27, 2010. On July 8, 2011, RFC and Met-Ed signed a settlement agreement to resolve all outstanding issues related to the vegetation encroachment event. The settlement calls for Met-Ed to pay a penalty of$650,000, and for FirstEnergy to perform certain mitigating actions. These mitigating actions include inspecting FirstEnergy's transmission system using LiDAR technology, and reporting the results of inspections, and any follow-up work, to RFC. FirstEnergy was performing the LiDAR work in response to certain other industry directives issued by NERC in 2010. NERC subsequently approved the settlement agreement and, on September 30, 2011, submitted the approved settlement to FERC for final approval. FERC approved the settlement agreement on October 28, 2011. Met-Ed subsequently paid the$650,000penalty and, on December 31, 2011, RFC sent written notice that this matter has been closed.

In 2011, RFC performed routine compliance audits of parts of FirstEnergy's bulk-power system and generally found the audited systems and process to be in full compliance with all audited reliability standards. RFC will perform additional audits in 2012.

MARYLAND
By statute enacted in 2007, the obligation of Maryland utilities to provide SOS to residential and small commercial customers, in exchange for recovery of their costs plus a reasonable profit, was extended indefinitely. The legislation also established a5-year cycle (to begin in 2008) for the MDPSC to report to the legislature on the status of SOS. PE now conducts rolling auctions to procure the power supply necessary to serve its customer load pursuant to a plan approved by the MDPSC. However, the terms on which PE will provide SOS to residential customers after the current settlement expires at the end of 2012 will depend on developments with respect to SOS in Maryland over the coming year, including but not limited to, possible MDPSC decisions in the proceedings discussed below.

The MDPSC opened a new docket in August 2007 to consider matters relating to possible “managed portfolio” approaches to SOS and other matters. “Phase II” of the case addressed utility purchases or construction of generation, bidding for procurement of demand response resources and possible alternatives if the TrAIL and PATH projects were delayed or defeated. It is unclear when the MDPSC will issue its findings in this proceeding.


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In September 2009, the MDPSC opened a new proceeding to receive and consider proposals for construction of new generation resources in Maryland. In December 2009, Governor Martin O'Malley filed a letter in this proceeding in which he characterized the electricity market in Maryland as a “failure” and urged the MDPSC to use its existing authority to order the construction of new generation in Maryland, vary the means used by utilities to procure generation and include more renewables in the generation mix. In December 2010, the MDPSC issued an order soliciting comments on a model RFP for solicitation of long-term energy commitments by Maryland electric utilities. PE and numerous other parties filed comments, and on September 29, 2011, the MDPSC issued an order requiring the utilities to issue the RFP crafted by the MDPSC by October 7, 2011. The RFPs were issued by the utilities as ordered by the MDPSC. The order, as amended, indicated that bids were due by January 20, 2012, and that the MDPSC would be the entity evaluating all bids. The Chairman of the MDPSC has stated publicly that several bids were received, but no other information was released. After receipt of further comments from interested parties, including PE, on January 13, 2012, a hearing on whether more generation is needed, irrespective of what bids may have been received, was held on January 31, 2012. There has been no further action on this matter.

In September 2007, the MDPSC issued an order that required the Maryland utilities to file detailed plans for how they will meet the “EmPOWER Maryland” proposal that electric consumption be reduced by10%and electricity demand be reduced by15%, in each case by 2015.

The Maryland legislature in 2008 adopted a statute codifying the EmPOWER Maryland goals. In 2008, PE filed its comprehensive plans for attempting to achieve those goals, asking the MDPSC to approve programs for residential, commercial, industrial, and governmental customers, as well as a customer education program. The MDPSC ultimately approved the programs in August 2009 after certain modifications had been made as required by the MDPSC, and approved cost recovery for the programs in October 2009. Expenditures were estimated to be approximately$101 millionfor the PE programs for the period of 2009 to 2015 and would be recovered over thatsixyear period. Meanwhile, after extensive meetings with the MDPSC Staff and other stakeholders, PE's plans for additional and improved programs for the period 2012-2014 were filed on August 31, 2011. The MDPSC held hearings on PE's and the other utilities' plans in October 2011, and on December 22, 2011, issued an order approving Potomac Edison's plan with various modifications and follow-up assignments. On January 23, 2012, PE filed a Request for Rehearing because additional facts not considered by the MDPSC demonstrate, among other things, that conservation voltage reduction program expenditures should be accorded cost recovery through the EmPOWER surcharge, as has been provided for all other EmPOWER programs as opposed to recovery of those expenditures being addressed in a future base rate case as the MDPSC found in its order.
In March 2009, the MDPSC issued an order temporarily suspending the right of all electric and gas utilities in the state to terminate service to residential customers for non-payment of bills. The MDPSC subsequently issued an order making various rule changes relating to terminations, payment plans, and customer deposits that make it more difficult for Maryland utilities to collect deposits or to terminate service for non-payment. The MDPSC is continuing to collect data on payment plan and related issues and has adopted regulations that expand the summer and winter “severe weather” termination moratoria when temperatures are very high or very low, fromoneday, as provided by statute, tothreedays on each occurrence.
The Maryland legislature passed a bill on April 11, 2011, which requires the MDPSC to promulgate rules by July 1, 2012 that address service interruptions, downed wire response, customer communication, vegetation management, equipment inspection, and annual reporting. In crafting the regulations, the legislation directs the MDPSC to consider cost-effectiveness, and provides that the MDPSC may adopt different standards for different utilities based on such factors as system design and existing infrastructure, geography, and customer density. Beginning in July 2013, the MDPSC is required to assess each utility's compliance with the new rules, and may assess penalties of up to$25,000per day per violation. The MDPSC convened a working group of utilities, regulators, and other interested stakeholders to address the topics of the proposed rules. A draft of the rules was filed, along with the report of the working group, on October 27, 2011. Hearings to consider the rules and comments occurred over four days between December 8 and 15, 2011, after which revised rules were sent for legislative review. The proposed rules were published in the Maryland Register on February 24, 2012, and a deadline of March 26, 2012, was set for the filing of further comments. A further hearing is required before the rules could become final. Separately, on July 7, 2011, the MDPSC adopted draft rules requiring monitoring and inspections for contact voltage. The draft rules were published in September, 2011. After a further hearing in October, 2011, the final rules were re-published and became effective on November 28, 2011.

NEW JERSEY

On September 8, 2011, the Division of Rate Counsel filed a Petition with the NJBPU asserting that it has reason to believe that JCP&L is earning an unreasonable return on its New Jersey jurisdictional rate base. The Division of Rate Counsel requests that the NJBPU order JCP&L to file a base rate case petition so that the NJBPU may determine whether JCP&L's current rates for electric service are just and reasonable. JCP&L filed an answer to the Petition on September 28, 2011, stating, inter alia, that the Division of Rate Counsel analysis upon which it premises its Petition contains errors and inaccuracies, that JCP&L's achieved return on equity is currently within a reasonable range, and that there is no reason for the NJBPU to require JCP&L to file a base rate case at this time.On November 30, 2011, the NJBPU ordered that the matter be assigned to the NJBPU President to act as presiding officer to set and modify the schedule for this matter as appropriate, decide upon motions, and otherwise control the conduct of this case, without the need for full Board approval. The matter is pending and a schedule for further proceedings has not yet been established.



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On September 22, 2011, the NJBPU ordered that JCP&L hire a Special Reliability Master, subject to NJBPU approval, to evaluate JCP&L's design, operating, maintenance and performance standards as they pertain to the Morristown, New Jersey underground electric distribution system, and make recommendations to JCP&L and the NJBPU on the appropriate courses of action necessary to ensure adequate reliability and safety in the Morristown underground network.On October 12, 2011, the Special Reliability Master was selected and on January 31, 2012, the project report was submitted to the Company and NJBPU Staff. On February 10, 2012, the NJBPU accepted the report and directed the Staff to present recommendations on March 12, 2012, on actions required by JCP&L to ensure the safe, reliable operation of the Morristown network.

Pursuant to a formal Notice issued by the NJBPU on September 14, 2011, public hearings were held on September 26 and 27, 2011, to solicit public comments regarding the state of preparedness and responsiveness of the local electric distribution companies prior to, during and after Hurricane Irene. By subsequent Notice issued September 28, 2011, additional hearings were held in October 2011. Additionally, the NJBPU accepted written comments through October 31, 2011 related to this inquiry.On December 4, 2011, the NJBPU Division of Reliability and Security issued a Request for Qualifications soliciting bid proposals from qualified consulting firms to provide expertise in the review and evaluation of New Jersey's electric distribution companies' preparation and restoration to Hurricane Irene and the October 2011 snowstorm. Responsive bids were submitted on January 20, 2012, and the report of selected bidder is to be submitted to the NJPBU 120 days from the date the contract is awarded. On December 14, 2011, the NJBPU Staff filed a report of its preliminary findings and recommendations with respect to the electric utility companies' planning and response to Hurricane Irene and the October 2011 snowstorm. The NJBPU has not indicated what additional action, if any, may be taken as a result of information obtained through this process.

OHIO

The Ohio Companies operate under an ESP, which expires on May 31, 2014. The material terms of the ESP include: generation supplied through a CBP commencing June 1, 2011; a load cap of no less than80%, which also applies to tranches assigned post-auction; a6%generation discount to certain low income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (FES is one of the wholesale suppliers to the Ohio Companies); no increase in base distribution rates through May 31, 2014; and a new distribution rider, Rider DCR, to recover a return of, and on, capital investments in the delivery system. The Ohio Companies also agreed not to recover from retail customers certain costs related to transmission cost allocations by PJM as a result of ATSI's integration into PJM for the longer of the five-year period from June 1, 2011 through May 31, 2015 or when the amount of costs avoided by customers for certain types of products totals$360 milliondependent on the outcome of certain PJM proceedings, agreed to establish a$12 millionfund to assist low income customers over the term of the ESP and agreed to additional matters related to energy efficiency and alternative energy requirements.

Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total annual energy savings equivalent to approximately166,000MWH in 2009,290,000MWH in 2010,410,000MWH in 2011,470,000MWH in 2012 and530,000MWH in 2013, with additional savings required through 2025. Utilities were also required to reduce peak demand in 2009 by1%, with an additional0.75%reduction each year thereafter through 2018.

In December 2009, the Ohio Companies filed the requiredthreeyear 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. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers in 2012. The PUCO issued an Opinion and Order generally approving the Ohio Companies'three-year plan, and the Ohio Companies are in the process of implementing those programs included in the Plan. OE fell short of its statutory 2010 energy efficiency and peak demand reduction benchmarks and therefore, on January 11, 2011, it requested that its 2010 energy efficiency and peak demand reduction benchmarks be amended to actual levels achieved in 2010. Moreover, because the PUCO indicated, when approving the 2009 benchmark request, that it would modify the Ohio Companies' 2010 (and 2011 and 2012) energy efficiency benchmarks when addressing the portfolio plan, the Ohio Companies were not certain of their 2010 energy efficiency obligations. Therefore, CEI and TE (each of which achieved its subsidiaries, are parties2010 energy efficiency and peak demand reduction statutory benchmarks) also requested an amendment if and only to a $2.75 billion five-year revolving credit facility. FirstEnergy has the abilitydegree one was deemed necessary to bring them into compliance with their yet-to-be-defined modified benchmarks. On May 19, 2011, the PUCO granted the request to reduce the 2010 energy efficiency and peak demand reductions to the level achieved in 2010 for OE, while finding that the motion was moot for CEI and TE. On June 2, 2011, the Ohio Companies filed an increaseapplication for rehearing to clarify the decision related to CEI and TE. On July 27, 2011, the PUCO denied that application for rehearing, but clarified that CEI and TE could apply for an amendment in the total commitments available under this facility upfuture for the 2010 benchmarks should it be necessary to do so. Failure to comply with the benchmarks or to obtain such an amendment may subject the Ohio Companies to an assessment of a maximum of $3.25 billion, subjectpenalty by the PUCO. In addition to approving the programs included in the plan, with only minor modifications, the PUCO authorized the Ohio Companies to recover all costs related to the discretion of each lender to provide additional commitments. Commitments underoriginal CFL program that the facility are available until August 24, 2012, unless the lenders agree,Ohio Companies had previously suspended at the request of the borrowers,PUCO. Applications for Rehearing were filed by the Ohio Companies, Ohio Energy Group and Nucor Steel Marion, Inc. on April 22, 2011, regarding portions of the PUCO's decision, including the method for calculating savings and certain changes made by the PUCO to specific programs. On September 7, 2011, the PUCO denied those applications for rehearing. The PUCO also included a new standard for compliance with the statutory energy efficiency benchmarks by requiring electric distribution companies to offer “all available cost effective energy efficiency opportunities” regardless of their level of compliance with the benchmarks as set forth in the statute.On October 7, 2011, the Ohio Companies, the Industrial Energy Users - Ohio, and the Ohio Energy Group filed applications for rehearing, arguing that the PUCO'S new standard is unlawful. The Ohio Companies also asked the PUCO to withdraw its amendment of CEI's and TE's 2010 energy efficiency benchmarks. The PUCO did not rule on the Applications for Rehearing within thirty days, thus denying them by operation of law. On December 30, 2011, the Ohio Companies


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filed a notice of appeal with the Supreme Court of Ohio, challenging the PUCO's new standard. No procedural schedule has been established.

Additionally, under SB221, electric utilities and electric service companies are required to serve part of their load in 2011 from renewable energy resources equivalent to1.00%of the average of the KWH they served in 2008-2010; in 2012 from renewable energy resources equivalent to1.50%of the average of the KWH they served in 2009-2011; and in 2013 from renewable energy resources equivalent to2.00%of the average of the KWH they served in 2010-2012. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RECs acquired through thesetwoRFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. In March 2010, the PUCO found that there was an unlimited numberinsufficient quantity of solar energy resources reasonably available in the market and reduced the Ohio Companies' aggregate 2009 benchmark to the level of SRECs the Ohio Companies acquired through their 2009 RFP processes, provided the Ohio Companies' 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC benchmark. On April 15, 2011, the Ohio Companies filed an application seeking an amendment to each of their 2010 alternative energy requirements for solar RECs generated in Ohio on the basis that an insufficient quantity of solar resources are available in the market but reflecting solar RECs that they have obtained and providing additional one-year extensions. Generally, borrowingsinformation regarding efforts to secure solar RECs. On August 3, 2011, the PUCO granted the Ohio Companies' force majeure request for 2010 and increased their 2011 benchmark by the amount of SRECs generated in Ohio that the Ohio Companies were short in 2010. On September 2, 2011, the Environmental Law and Policy Center and Nucor Steel Marion, Inc. filed applications for rehearing. The Ohio Companies filed their response on September 12, 2011. These applications for rehearing were denied by the PUCO on September 20, 2011, but as part of its Entry on Rehearing the PUCO opened a new docket to review the Ohio Companies' alternative energy recovery rider. Separately,oneparty has filed a request that the PUCO audit the cost of the Ohio Companies' compliance with the alternative energy requirements and the Ohio Companies' compliance with Ohio law. The PUCO selected auditors to perform a financial and a management audit, and final audit reports are to be filed with the PUCO by May 15, 2012. In August 2011, the Ohio Companies conducted two RFP processes to obtain RECs to meet the statutory benchmarks for 2011 and beyond.

PENNSYLVANIA
The PPUC entered an Order on March 3, 2010 that denied the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, directed Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructed Met-Ed and Penelec to work with the various intervening parties to file a recommendation to the PPUC regarding the establishment of a separate account for all marginal transmission losses collected from customers plus interest to be used to mitigate future generation rate increases beginning January 1, 2011. In March 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 to end collection of costs for marginal transmission losses. The PPUC granted the requested stay until December 31, 2010. Pursuant to the PPUC's order, Met-Ed and Penelec filed plans to establish separate accounts for marginal transmission loss revenues and related interest and carrying charges. Pursuant to the plan approved by the PPUC, Met-Ed and Penelec began to refund those amounts to customers in January 2011, and the refunds are continuing over a 29 month period until the full amounts previously recovered for marginal transmission loses are refunded. In April 2010, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania appealing the PPUC's March 3, 2010 Order. On June 14, 2011, the Commonwealth Court issued an opinion and order affirming the PPUC's Order to the extent that it holds that line loss costs are not transmission costs and, therefore, the approximately$254 millionin marginal transmission losses and associated carrying charges for the period prior to January 1, 2011, are not recoverable under Met-Ed's and Penelec's TSC riders. Met-Ed and Penelec filed a Petition for Allowance of Appeal with the facility mustPennsylvania Supreme Court and also a complaint seeking relief in the U.S. District Court for the Eastern District of Pennsylvania, which was subsequently amended. The PPUC filed a Motion to Dismiss Met-Ed's and Penelec's Amended Complaint on September 15, 2011. Met-Ed and Penelec filed a Responsive brief in Opposition to the PPUC's Motion to Dismiss on October 11, 2011. Although the ultimate outcome of this matter cannot be repaid within 364 days. Available amounts determined at this time, Met-Ed and Penelec believe that they should ultimately prevail through the judicial process and therefore expect to fully recover the approximately$254 million($189 millionfor Met-Ed and$65 millionfor Penelec) in marginal transmission losses for the period prior to January 1, 2011.

In each borrowerof May 2008, 2009 and 2010, the PPUC approved Met-Ed's and Penelec's annual updates to their TSC rider for the annual periods between June 1, 2008 to 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 PPUC's approval in May 2010 authorized an increase to the TSC for Met-Ed's customers to provide for full recovery by December 31, 2010.

In February 2010, Penn filed a Petition for Approval of its DSP for the period June 1, 2011 through May 31, 2013. In July 2010, the parties to the proceeding filed a Joint Petition for Settlement of all issues. Although the PPUC's Order approving the Joint Petition held that the provisions relating to the recovery of MISO exit fees and one-time PJM integration costs (resulting from Penn's June 1, 2011 exit from MISO and integration into PJM) were approved, it made such provisions subject to the approval of cost recovery by FERC. Therefore, Penn may not put these provisions into effect until FERC has approved the recovery and allocation of MISO exit fees and PJM integration costs.

Pennsylvania adopted Act 129 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


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energy efficiency and peak load reduction plan, (EE&C Plan), by July 1, 2009, setting forth the utilities' plans to reduce energy consumption by a minimum of1%and3%by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of4.5%by May 31, 2013. Act 129 provides for potentially significant financial penalties to be assessed upon utilities that fail to achieve the required reductions in consumption and peak demand. Act 129 also required utilities to file a SMIP with the PPUC.

The PPUC entered an Order in February 2010 giving final approval to all aspects of the EE&C Plans of Met-Ed, Penelec and Penn and the tariff rider became effective March 1, 2010. On February 18, 2011, the companies filed a petition to approve their First Amended EE&C Plans. On June 28, 2011, a hearing on the petition was held before an ALJ.On December 15, 2011, the ALJ recommended that the amended plans be approved as proposed, and on January 12, 2012, the Commission approved the plans.
WP filed its original EE&C Plan in June 2009, which the PPUC approved, in large part, by Opinion and Order entered in October 2009. In September 2010, WP filed an amended EE&C Plan that is less reliant on smart meter deployment, which the PPUC approved in January 2011.
On August 9, 2011, WP filed a petition to approve its Second Amended EE&C Plan. The proposed Second Revised Plan includes measures and a new program and implementation strategies consistent with the successful EE&C programs of Met-Ed, Penelec and Penn that are designed to enable WP to achieve the post-2011 Act 129 EE&C requirements.On January 6, 2012, a Joint Petition for Settlement of all issues was filed by the parties to the proceeding.

The Pennsylvania Companies submitted a preliminary report on July 15, 2011, and a final report on November 15, 2011, in which they reported on their compliance with statutory May 31, 2011, energy efficiency benchmarks.Met-Ed, Penelec and Penn achieved the 2011 benchmarks; however WP has been unable to provide final results because several customers are still accumulating necessary documentation for projects that may qualify for inclusion in the final results. Preliminary numbers indicate that WP did not achieve its 2011 benchmark and it is not known at this time whether WP will be subject to a specified sub-limit,fine for failure to achieve the benchmark. WP is unable to predict the outcome of this matter or estimate any possible loss or range of loss.

In December 2009, WP filed a motion to reopen the evidentiary record to submit an alternative smart meter plan proposing, among other things, a less-rapid deployment of smart meters.

In light of the significant expenditures that would be associated with its smart meter deployment plans and related infrastructure upgrades, as well as applicable regulatoryits evaluation of recent PPUC decisions approving less-rapid deployment proposals by other utilities, WP re-evaluated its Act 129 compliance strategy, including both its plans with respect to smart meter deployment and certain smart meter dependent aspects of the EE&C Plan. In October 2010, WP and Pennsylvania's OCA filed a Joint Petition for Settlement addressing WP's smart meter implementation plan with the PPUC. Under the terms of the proposed settlement, WP proposed to decelerate its previously contemplated smart meter deployment schedule and to target the installation of approximately25,000smart meters in support of its EE&C Plan, based on customer requests, by mid-2012. The proposed settlement also contemplates that WP take advantage of the30-month grace period authorized by the PPUC to continue WP's efforts to re-evaluate full-scale smart meter deployment plans. WP currently anticipates filing its plan for full-scale deployment of smart meters in June 2012. Under the terms of the proposed settlement, WP would be permitted to recover certain previously incurred and anticipated smart-meter related expenditures through a levelized customer surcharge, with certain expenditures amortized over a ten-year period. Additionally, WP would be permitted to seek recovery of certain other limitations.costs as part of its revised SMIP that it currently intends to file in June 2012, or in a future base distribution rate case.
Following additional proceedings, on March 9, 2011, WP submitted an Amended Joint Petition for Settlement which restates the Joint Petition for Settlement filed in October 2010, adds the PPUC's Office of Trial Staff as a signatory party, and confirms the support or non-opposition of all parties to the settlement.Oneparty retained the ability to challenge the recovery of amounts spent on WP's original smart meter implementation plan. A Joint Stipulation with the OSBA was also filed on March 9, 2011. The annual facility fee is 0.125%.PPUC approved the Amended Joint Petition for Full Settlement by order entered June 30, 2011.

By Tentative Order entered in September 2009, the PPUC provided for an additional30-day comment period on whether the 1998 Restructuring Settlement, which addressed how Met-Ed and Penelec were going to implement direct access to a competitive market for the generation of electricity, allows Met-Ed and Penelec to apply over-collection of NUG costs for select and isolated months to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists. In response to the Tentative Order, various parties filed comments objecting to the accounting method utilized by Met-Ed and Penelec.On January 30, 2012, the Commission entered a final order approving Met-Ed's and Penelec's accounting methodology whereby NUG over-collection revenue may be used to reduce non-NUG stranded costs, even if a cumulative NUG stranded cost balance exists.

In the PPUC Order approving the FirstEnergy and Allegheny merger, the PPUC announced that a separate statewide investigation into Pennsylvania's retail electricity market will be conducted with the goal of making recommendations for improvements to ensure that a properly functioning and workable competitive retail electricity market exists in the state. On April 29, 2011, the PPUC entered an Order initiating the investigation and requesting comments from interested parties on eleven directed questions concerning retail markets in Pennsylvania. Met-Ed, Penelec, Penn Power and WP submitted joint comments on June 3, 2011. FES also submitted comments on June 3, 2011. On June 8, 2011, the PPUC conducted an en banc hearing on these issues at which both the Pennsylvania Companies and FES participated and offered testimony.A technical conference was held on August 10, 2011, and a second en banc was held on November 10, 2011, to discuss intermediate steps that can be taken to promote the development of a competitive


240
230


market. Teleconferences are scheduled through March 2012, with another en banc hearing to be held on March 21, 2012, to explore the future of default service in Pennsylvania following the expiration of the upcoming default service plans on May 31, 2015. Following the issuance of a Tentative Order and comments filed by numerous parties, the Commission entered a final order on December 16, 2011, providing recommendations for components to be included in upcoming default service plans. An intermediate work plan was also presented on December 16, 2011, by Tentative Order, on which initial comments were submitted by Met-Ed, Penelec, Penn and WP on January 17, 2012. FES also submitted comments. Reply comments were submitted on February 1, 2012. It is expected that a final order implementing the intermediate work plan and a long range plan will be presented by the PPUC, both in March 2012.

The following table summarizesPPUC issued a Proposed Rulemaking Order on August 25, 2011, which proposed a number of substantial modifications to the borrowing sub-limitscurrent Code of Conduct regulations that were promulgated to provide competitive safeguards to the competitive retail electric market in Pennsylvania. The proposed changes include, but are not limited to: an EGS may not have the same or substantially similar name as the EDC or its corporate parent; EDCs and EGSs would not be permitted to share office space and would need to occupy different buildings; EDCs and affiliated EGSs could not share employees or services, except certain corporate support, emergency, or tariff services (the definition of "corporate support services" excludes items such as information systems, electronic data interchange, strategic management and planning, regulatory services, legal services, or commodities that have been included in regulated rates at less than market value); and an EGS must enter into a trademark agreement with the EDC before using its trademark or service mark. The Proposed Rulemaking Order, which was published on February 11, 2012, calls for comments to be submitted by March 27, 2012. If implemented these rules could require a significant change in the way FES, Met-Ed, Penelec, Penn and WP do business in Pennsylvania, and could possibly have an adverse impact on their results of operations and financial condition.

In November 2011, Met-Ed, Penelec, Penn and WP filed a Joint Petition for Approval of their Default Service Plan for the period June 1, 2013 through May 31, 2015. The Pennsylvania Companies' direct case was submitted in its entirety on December 20, 2011. Evidentiary hearings are scheduled for April 11-13, 2012, and a final order must be entered by the PPUC by August 17, 2012.

WEST VIRGINIA
In 2009, the West Virginia Legislature enacted the AREPA, which generally requires that a specified minimum percentage of electricity sold to retail customers in West Virginia by electric utilities each borroweryear be derived from alternative and renewable energy resources according to a predetermined schedule of increasing percentage targets, including10%by 2015,15%by 2020, and25%by 2025. In November 2010, the WVPSC issued RPS Rules, which became effective on January 4, 2011. Under the RPS Rules, on or before January 1, 2011, each electric utility subject to the provisions of this rule was required to prepare an alternative and renewable energy portfolio standard compliance plan and file an application with the WVPSC seeking approval of such plan. MP and PE filed their combined compliance plan in December 2010. A hearing was held at the WVPSC on June 13, 2011. An order was issued by the WVPSC in September 2011, which conditionally approved MP's and PE's compliance plan, contingent on the outcome of the resource credits case discussed below.

Additionally, in January 2011, MP and PE filed an application with the WVPSC seeking to certify three facilities as Qualified Energy Resource Facilities. The application was approved and the three facilities are capable of generating renewable credits which will assist the companies in meeting their combined requirements under the facility,AREPA. An annual update filing is due on March 31, 2012. Further, in February 2011, MP and PE filed a petition with the WVPSC seeking an Order declaring that MP is entitled to all alternative and renewable energy resource credits associated with the electric energy, or energy and capacity, that MP is required to purchase pursuant to electric energy purchase agreements between MP and three non-utility electric generating facilities in West Virginia. The City of New Martinsville and Morgantown Energy Associates, each the owner of one of the contracted resources, has participated in the case in opposition to the Petition. A hearing was held at the WVPSC on August 25 and 26, 2011.On November 22, 2011, the WVPSC issued an order granting ownership of all RECs produced by the facilities to MP. On December 22, 2011, the WVPSC order was appealed, and the order was stayed pending the outcome of the appeal. MP's brief was filed on February 13, 2012. Should MP be unsuccessful in the appeal, it will have to procure the requisite RECs to comply with AREPA from other sources. MP expects to recover such costs from customers.

In September 2011, MP and PE filed with the WVPSC to recover costs associated with fuel and purchased power (the ENEC) in the amount of$32 millionwhich represents an approximate3%overall increase in such costs over the past two years, primarily attributable to rising coal prices. The requested increase was partially offset by$2.5 millionof synergy savings directly resulting from the merger of FirstEnergy and AE, which closed in February 2011. Under a cost recovery clause established by the WVPSC in 2007, MP and PE customer bills are adjusted periodically to reflect upward or downward changes in the cost of fuel and purchased power. The utilities' most recent request to recover costs for fuel and purchased power was in September 2009.MP and PE entered into a Settlement Agreement related to this matter. The WVPSC issued an order on December 30, 2011, approving the settlement agreement. The approved settlement resulted in an increase of$19.6 million, instead of the requested$32 million, with additional costs to be recovered over time with a carrying charge.



241


FERC MATTERS

PJM Transmission Rate

In April 2007, FERC issued 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, FERC directed that costs for new transmission facilities that are rated at500kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate based on the amount of load served in a transmission zone. Costs for new transmission facilities that are rated at less than500kV, however, are to be allocated on a load flow methodology, which is generally referred to as a “beneficiary pays” approach to allocating the cost of high voltage transmission facilities.

FERC's Opinion 494 order was appealed to the U.S. Court of Appeals for the Seventh Circuit, which issued a decision in August 2009. The court affirmed FERC's ratemaking treatment for existing transmission facilities, but found that FERC had not supported its decision to allocate costs for new500kV and higher voltage facilities on a load ratio share basis and, based on this finding, remanded the rate design issue to FERC.

In an order dated January 21, 2010, FERC set the matter for a “paper hearing” and requested parties to submit written comments pursuant to the schedule described in the order. FERC identifiednineseparate issues for comments and directed PJM to file the first round of comments on February 22, 2010, with other parties submitting responsive comments and then reply comments on later dates. PJM filed certain studies with FERC on April 13, 2010, in response to the FERC order. PJM's filing demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain load serving entities in PJM bearing the majority of the 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. Other utilities and state commissions supported continued socialization of these costs on a load ratio share basis. This matter is awaiting action by FERC. FirstEnergy cannot predict the outcome of this matter or estimate the possible loss or range of loss.

RTO Realignment

On June 1, 2011, ATSI and the ATSI zone entered into PJM. The move was performed as planned with no known operational or reliability issues for ATSI or for the wholesale transmission customers in the ATSI zone.

On February 1, 2011, ATSI in conjunction with PJM filed its proposal with FERC for moving its transmission rate into PJM's tariffs. On April 1, 2011, the MISO TOs (including ATSI) filed proposed tariff language that describes the mechanics of collecting and administering MTEP costs from ATSI-zone ratepayers. From March 20, 2011 through April 1, 2011, FirstEnergy, PJM and the MISO submitted numerous filings for the purpose of effecting movement of the ATSI zone to PJM on June 1, 2011. These filings include amendments to the MISO's tariffs (to remove the ATSI zone), submission of load and generation interconnection agreements to reflect the move into PJM, and submission of changes to PJM's tariffs to support the move into PJM.

On May 31, 2011, FERC issued orders that address the proposed ATSI transmission rate, and certain parts of the MISO tariffs that reflect the mechanics of transmission cost allocation and collection. In its May 31, 2011 orders, FERC approved ATSI's proposal to move the ATSI formula rate into the PJM tariff without significant change. Speaking to ATSI's proposed treatment of the MISO's exit fees and charges for transmission costs that were allocated to the ATSI zone, FERC required ATSI to present a cost-benefit study that demonstrates that the benefits of the move for transmission customers exceed the costs of any such move, which FERC had not previously required. Accordingly, FERC ruled that these costs must be removed from ATSI's proposed transmission rates until such time as ATSI files and FERC approves the cost-benefit study. On June 30, 2011, ATSI submitted the compliance filing that removed the MISO exit fees and transmission cost allocation charges from ATSI's proposed transmission rates. Also on June 30, 2011, ATSI requested rehearing of FERC's decision to require a cost-benefit analysis as part of FERC's evaluation of ATSI's proposed transmission rates. Finally, and also on June 30, 2011, the MISO and the MISO TOs filed a competing compliance filing - one that would require ATSI to pay certain charges related to construction and operation of transmission projects within the MISO even though FERC ruled that ATSI cannot pass these costs on to ATSI's customers. ATSI on the one hand, and the MISO and MISO TOs on the other, have submitted subsequent filings - each of which is intended to refute the other's claims. ATSI's compliance filing and request for rehearing, as well as the limitations on short-term indebtedness applicable to each borrower under current regulatory approvalspleadings that reflect the dispute between ATSI and applicable statutory and/or charter limitations as of December 31, 2009:the MISO/MISO TOs, are currently pending before FERC.

  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   33 (2) 
CEI  250(3)   500  
TE  250(3)  500  
JCP&L  425   411(2) 
Met-Ed  250   300(2) 
Penelec  250   300(2)  
ATSI  50(4)  50  
From late April 2011 through June 2011, FERC issued other orders that address ATSI's move into PJM. Also, ATSI and the MISO were able to negotiate an agreement of ATSI's responsibility for certain charges associated with long term firm transmission rights that, according to the MISO, were payable by the ATSI zone upon its departure from the MISO. ATSI did not and does not agree that these costs should be charged to ATSI but, in order to settle the case and all claims associated with the case, ATSI agreed to a one-time payment of$1.8 millionto the MISO. This settlement agreement has been submitted for FERC's review and approval. The final outcome of those proceedings that address the remaining open issues related to ATSI's move into PJM and their impact, if any, on FirstEnergy cannot be predicted at this time.



(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 ATSI has received regulatory approval to have short-term borrowings up to the same amount.
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MISO Multi-Value Project Rule Proposal

In July 2010, MISO and certain MISO transmission owners jointly filed with FERC their proposed cost allocation methodology for certain new transmission projects. The regulated companies also havenew transmission projects--described as MVPs - are a class of transmission projects that are approved via the abilityMTEP. The filing parties proposed to borrow from each otherallocate the costs of MVPs by means of a usage-based charge that will be applied to all loads within the MISO footprint, and FirstEnergy to meet their short-term working capital requirements. A similar but separate arrangement exists amongenergy transactions that call for power to be “wheeled through” the unregulated companies. FESC administers these two money pools and tracks FirstEnergy’s surplus funds and those of the respective regulated and unregulated subsidiaries,MISO as well as proceeds availableto energy transactions that “source” in the MISO but “sink” outside of MISO. The filing parties expect that the MVP proposal will fund the costs of large transmission projects designed to bring wind generation from bank borrowings. Companies receivingthe upper Midwest to load centers in the east. The filing parties requested an effective date for the proposal of July 16, 2011. On August 19, 2010, MISO's Board approved the first MVP project -- the “Michigan Thumb Project.” Under MISO's proposal, the costs of MVP projects approved by MISO's Board prior to the June 1, 2011 effective date of FirstEnergy's integration into PJM would continue to be allocated to FirstEnergy. MISO estimated that approximately$15 millionin annual revenue requirements would be allocated to the ATSI zone associated with the Michigan Thumb Project upon its completion.

In September 2010, FirstEnergy filed a loan underprotest to the money pool agreements must repayMVP proposal arguing that MISO's proposal to allocate costs of MVPs projects across the principalentire MISO footprint does not align with the established rule that cost allocation is to be based on cost causation (the “beneficiary pays” approach). FirstEnergy also argued that, in light of progress that had been made to date in the ATSI integration into PJM, it would be unjust and unreasonable to allocate any MVP costs to the ATSI zone, or to ATSI. Numerous other parties filed pleadings on MISO's MVP proposal.

In December 2010, FERC issued an order approving the MVP proposal without significant change. Despite being presented with the issue by FirstEnergy and the MISO, the FERC did not address clearly the question of whether the MVP costs would be payable by ATSI or load in the ATSI zone. FERC stated that the MISO's tariffs obligate ATSI to pay all charges that attached prior to ATSI's exit but ruled that the question of the amount of costs that are to be allocated to ATSI or to load in the loan, togetherATSI zone were beyond the scope of FERC's order and would be addressed in future proceedings.

On January 18, 2011, FirstEnergy requested rehearing of FERC's order. In its rehearing request, FirstEnergy argued that because the MVP rate is usage-based, costs could not be applied to ATSI, which is a stand-alone transmission company that does not use the transmission system. FirstEnergy also renewed its arguments regarding cost causation and the impropriety of allocating costs to the ATSI zone or to ATSI.On October 21, 2011, FERC issued its order on rehearing, but that order did not address FirstEnergy's argument directly. FERC ruled instead that if ATSI was subject to MVP charges then ATSI owed these charges upon exit of the MISO. On October 31, 2011, FESC filed a Petition of Review for the FERC's December 2010 order and October 21, 2011 order on rehearing of that order with accrued interest, within 364 daysthe U.S. Court of borrowingAppeals for the funds. The rateD.C. Circuit. Other parties also filed appeals of interest isthose orders and, in November, 2011, the samecases were consolidated for each company receivingbriefing and disposition in the U.S. Court of Appeals for the Seventh Circuit. On January 27, 2012, the court ordered the FERC to file a loan from their respective poolproposed briefing format and isschedule on or before March 20, 2012.

On August 3, 2011, FirstEnergy filed a complaint with FERC based on the average costFERC's December 2010 order. In the complaint, FirstEnergy argued that ATSI perfected the legal and financial requirements necessary to exit MISO before any MVP responsibilities could attach and asked FERC to rule that MISO cannot charge ATSI for MVP costs. On September 2, 2011, MISO, its TOs and other parties, filed responsive pleadings. On September 19, 2011, ATSI filed an answer. On December 29, 2011, the MISO and the MISO TOs filed a new “Schedule 39” to the MISO's tariff. Schedule 39 purports to establish a process whereby the MISO would bill TOs for MVP costs that, according to the MISO, attached to the utility prior to such TOs withdrawal from the MISO. On January 19, 2012, FirstEnergy filed a protest to the MISO's new Schedule 39 tariff.

On February 27, 2012, FERC issued an order (February 2012 Order) dismissing ATSI's August 3, 2011 complaint. In the February 2012 Order, FERC accepted the MISO's Schedule 39 tariff, subject to hearings and potential refund of MVP charges to ATSI. The basis for any subsequent hearing is whether the Schedule 39 tariff was in effect at the time that ATSI exited the MISO. FirstEnergy is evaluating the February 2012 Order and will determine the next steps.

FirstEnergy cannot predict the outcome of these proceedings or estimate the possible loss or range of loss.

FirstEnergy Companies' PJM Underfunding FTR Contract Complaint

On December 28, 2011, FES and AE Supply filed a complaint with FERC against PJM challenging the ongoing underfunding of FTR contracts, which exist to hedge against transmission congestion in the day-ahead markets. The underfunding is a result of PJM's practice of using the funds available throughthat are intended to pay the pool. The average interest rateholders of FTR contracts to pay instead for borrowingscongestion costs that occur in 2009 was 0.72%the real time markets. Underfunding of the FTR contracts resulted in losses of approximately$35 millionto FES and AE Supply in the 2010-2011 Delivery Year. To date, losses for the regulated companies’ money pool2011-2012 Delivery Year are estimated to be approximately$6 million.

On January 13, 2012, PJM filed comments that describe changes to the PJM tariff that, if adopted, should remedy the underfunding issue. Many parties also filed comments supporting FES' and 0.90%AE Supply's position. Other parties, generally representatives of end-use customers who will have to pay the charges, filed in opposition to the complaint. The matter is currently pending before FERC. FirstEnergy cannot predict the outcome of this matter or estimate the possible loss or range of loss.



243


California Claims Matters

In October 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the CDWR during 2001. The settlement proposal claims that CDWR is owed approximately$190 millionfor these alleged overcharges. This proposal was made in the context of mediation efforts by FERC and the United States Court of Appeals for the unregulated companies’ money pool.Ninth Circuit in pending proceedings to resolve all outstanding refund and other claims, including claims of alleged price manipulation in the California energy markets during 2000 and 2001. The Ninth Circuit has since remandedoneof those proceedings to FERC, which arises out of claims previously filed with FERC by the California Attorney General on behalf of certain California parties against various sellers in the California wholesale power market, including AE Supply (the Lockyer case). AE Supply and several other sellers filed motions to dismiss the Lockyer case. In March 2010, the judge assigned to the case entered an opinion that granted the motions to dismiss filed by AE Supply and other sellers and dismissed the claims of the California Parties. On May 4, 2011, FERC affirmed the judge's ruling. On June 3, 2011, the California parties requested rehearing of the May 4, 2011 order. The request for rehearing remains pending.

In June 2009, the California Attorney General, on behalf of certain California parties, filed a second complaint with FERC against various sellers, including AE Supply (the Brown case), again seeking refunds for trades in the California energy markets during 2000 and 2001. The weighted average interest ratesabove-noted trades with CDWR are the basis for including AE Supply in this new complaint. AE Supply filed a motion to dismiss the Brown complaint that was granted by FERC on short-term borrowings outstandingMay 24, 2011. On June 23, 2011, the California Attorney General requested rehearing of the May 24, 2011 order. That request for rehearing also remains pending. FirstEnergy cannot predict the outcome of either of the above matters or estimate the possible loss or range of loss.

PATH Transmission Project

The PATH Project is comprised of a765kV transmission line that was proposed to extend from West Virginia through Virginia and into Maryland, modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland.

PJM initially authorized construction of the PATH Project in June 2007. In December 2010, PJM advised that its 2011 Load Forecast Report included load projections that are different from previous forecasts and that may have an impact on the proposed in-service date for the PATH Project. As part of its 2011 RTEP, and in response to a January 19, 2011, directive by a Virginia Hearing Examiner, PJM conducted a series of analyses using the most current economic forecasts and demand response commitments, as well as potential new generation resources. Preliminary analysis revealed the expected reliability violations that necessitated the PATH Project had moved several years into the future. Based on those results, PJM announced on February 28, 2011, that its Board of Managers had decided to hold the PATH Project in abeyance in its 2011 RTEP and directed FirstEnergy and AEP, as the sponsoring transmission owners, to suspend current development efforts on the project, subject to those activities necessary to maintain the project in its current state, while PJM conducts more rigorous analysis of the need for the project as part of its continuing RTEP process. PJM stated that its action did not constitute a directive to FirstEnergy and AEP to cancel or abandon the PATH Project. PJM further stated that it will complete a more rigorous analysis of the PATH Project and other transmission requirements and its Board will review this comprehensive analysis as part of its consideration of the 2011 RTEP. On February 28, 2011, affiliates of FirstEnergy and AEP filed motions or notices to withdraw applications for authorization to construct the project that were pending before state commissions in West Virginia, Virginia and Maryland. Withdrawal was deemed effective upon filing the notice with the MDPSC. The WVPSC and VSCC have granted the motions to withdraw.

PATH submitted a filing to FERC to implement a formula rate tariff effective March 1, 2008. In a November 19, 2010 order addressing various matters relating to the formula rate, FERC set the project's base ROE for hearing and reaffirmed its prior authorization of a return on CWIP, recovery of start-up costs and recovery of abandonment costs. In the order, FERC also granted a1.5%ROE incentive adder and a0.5%ROE adder for RTO participation. These adders will be applied to the base ROE determined as a result of the hearing. The PATH Companies, Joint Intervenors, Joint Consumer Advocates and FERC staff have agreed to a four year moratorium. A settlement was reached, which reflects a base ROE of10.4%(plus authorized adders) effective January 1, 2011. Accordingly, the revised ROE was reflected in a revised Projected Transmission Revenue Requirement for 2011 with true-up occurring in 2013. The FirstEnergy portion of the refund for March 1, 2008, through December 31, 20092010, is approximately$2 million(inclusive of interest). The refund amount was computed using a base ROE of10.8%plus authorized adders. On October 7, 2011, PATH and 2008 weresix intervenors submitted to FERC an unopposed settlement agreement. Contemporaneous with this submission, PATH and the six intervenors filed with the Chief ALJ of FERC a joint motion for interim approval and authorization to implement the refund on an interim basis pending issuance of a FERC order acting on the settlement agreement. On October 12, 2011, the motion for interim approval and authorization to implement the refund was granted by the Chief ALJ. On February 16, 2012, FERC approved the settlement agreement and dismissed as follows:moot, in light of its approval of the settlement, PATH's pending request for rehearing of the November 19, 2010 order.
Yards Creek
The Yards Creek Pumped Storage Project is a400MW hydroelectric project located in Warren County, New Jersey. JCP&L owns an undivided50%interest in the project, and operates the project. PSEG Fossil, LLC, a subsidiary of Public Service Enterprise Group, owns the remaining interest in the plant. The project was constructed in the early 1960s, and became operational in 1965.


244


Authorization to operate the project is by a license issued by the FERC. The existing license expires on February 28, 2013.

  2009  2008 
FE
  0.74%  1.19%
FES
  1.84%  1.08%
OE(1)
  0.72%  - 
CEI
  1.13%  1.77%
TE
  0.72%  1.46%
JCP&L(2)
  -   1.46%
Met-Ed(2)
  -   0.92%
Penelec
  0.72%  0.95%
In February 2011, JCP&L and PSEG filed a joint application with FERC to renew the license for an additional forty years. The companies are pursuing relicensure through FERC's ILP. Under the ILP, FERC will assess the license applications, issue draft and final Environmental Assessments/Environmental Impact Studies (as required by NEPA), and provide opportunities for intervention and protests by affected third parties. FERC may hold hearings during the two-year ILP licensure period. FirstEnergy expects FERC to issue the new license within the remaining portion of the two-year ILP period. To the extent, however, that the license proceedings extend beyond the February 28, 2013 expiration date for the current license, the current license will be extended yearly as necessary to permit FERC to issue the new license.
Seneca
(1)In, 2008, OE's short-term borrowings consisted of noninterest-bearing notes related to its investment in certain low-income housing limited partnerships.
(2)JCP&L and Met-Ed had no outstanding short-term borrowings as of December 31, 2009.

The Seneca Pumped Storage Project is a451MW hydroelectric project located in Warren County, Pennsylvania owned and operated by FGCO. FGCO holds the current FERC license that authorizes ownership and operation of the project. The current FERC license will expire on November 30, 2015. FERC's regulations call for a five-year relicensing process. On November 24, 2010, and acting pursuant to applicable FERC regulations and rules, FGCO initiated the relicensing process by filing its notice of intent to relicense and PAD in the license docket.

231On November 30, 2010, the Seneca Nation filed its notice of intent to relicense and PADs necessary for them to submit a competing application. Section 15 of the FPA contemplates that third parties may file a "competing application" to assume ownership and operation of a hydroelectric facility upon (i) relicensure and (ii) payment of net book value of the plant to the original owner/operator. Nonetheless, FGCO believes it is entitled to a statutory “incumbent preference” under Section 15.


The Utilities,Seneca Nation and certain other intervenors have asked FERC to redefine the “project boundary” of the hydroelectric plant to include the dam and reservoir facilities operated by the U.S. Army Corps of Engineers. On May 16, 2011, FirstEnergy filed a Petition for Declaratory Order with FERC seeking an order to exclude the dam and reservoir facilities from the project. The Seneca Nation, the New York State Department of Environmental Conservation, and the U.S. Department of Interior each submitted responses to FirstEnergy's petition, including motions to dismiss FirstEnergy's petition. The “project boundary” issue is pending before FERC.

On September 12, 2011, FirstEnergy and the Seneca Nation each filed “Revised Study Plan” documents. These documents describe the parties' respective proposals for the scope of the environmental studies that should be performed as part of the relicensing process. On October 11, 2011, FERC Staff issued a letter order that addressed the Revised Study Plans. In the order, FERC Staff approved FirstEnergy's Revised Study Plan, subject to a finding that the Project is located on “aboriginal lands” of the Seneca Nation. Based on this finding, FERC Staff directed FirstEnergy to consult with the exceptionSeneca Nation and other parties about the data set, methodology, and modeling of TE, JCP&L and Penn, each havethe hydrological impacts of project operations. FirstEnergy is performing the work necessary to develop a wholly owned subsidiary whose borrowings are secured by customer accounts receivable purchasedstudy proposal from its respective parent company.which to conduct such consultations. The CEI subsidiary's borrowings are also secured by customer accounts receivable purchased from TE. Each subsidiary company has its own receivables financing arrangement and, as a separate legal entity with separate creditors, would have to satisfy its obligations to creditors before anystudy process will extend through approximately November of its remaining assets could be available to its parent company. In December 2009, the Met-Ed and Penelec Funding LLC receivables programs were renewed for a 364-day period. The Penn Power Funding LLC program was not renewed in 2009 and was thereafter terminated effective December 17, 2009. The receivables financing borrowing commitment by company are shown in the following table. There were no outstanding borrowings as of December 31, 2009.2013.

Subsidiary Company 
Parent
Company
 Commitment 
Annual
Facility Fee
  Maturity
  (In millions)   
OES Capital, Incorporated OE $170 0.20% February 22, 2010
Centerior Funding Corporation CEI 200 0.20  February 22, 2010
Met-Ed Funding LLC Met-Ed 75 0.60  December 17, 2010
Penelec Funding LLC Penelec 70 0.60  December 17, 2010
    $515     
FirstEnergy cannot predict the outcome of this matter or estimate the possible loss or range of loss.
16. COMMITMENTS, GUARANTEES AND CONTINGENCIES

NUCLEAR INSURANCE
15.COMMITMENTS, GUARANTEES AND CONTINGENCIES

(A)NUCLEAR INSURANCE

The Price-Anderson Act limits the public liability which can be assessed with respect to a nuclear power plant to $12.6$12.6 billion (assuming 104 units licensed to operate) for a single nuclear incident, which amount is covered by: (i) private insurance amounting to $375 million;$375 million; and (ii) $12.2$12.2 billion provided by an industry retrospective rating plan required by the NRC pursuant thereto. Under such retrospective rating plan, in the event of a nuclear incident at any unit in the United States resulting in losses in excess of private insurance, up to $118$118 million (but not more than $18$18 million per unit per year in the event of more than one incident) must be contributed for each nuclear unit licensed to operate in the country by the licensees thereof to cover liabilities arising out of the incident. Based on their present nuclear ownership and leasehold interests, FirstEnergy’s maximum potential assessment under these provisions would be $470$470 million (OE-$40 million, NGC-$408 million, and TE-$22 million)million) per incident but not more than $70$70 million (OE-$6 million, NGC-$61 million, and TE-$3 million)million) in any one year for each incident.

In addition to the public liability insurance provided pursuant to the Price-Anderson Act, FirstEnergy has also obtained insurance coverage in limited amounts for economic loss and property damage arising out of nuclear incidents. FirstEnergy is a member of NEIL, which provides coverage (NEIL I) for the extra expense of replacement power incurred due to prolonged accidental outages of nuclear units. Under NEIL I, FirstEnergy’s subsidiaries have policies, renewable yearly, corresponding to their respective nuclear interests, which provide an aggregate indemnity of up to approximately $560$2.0 billion (OE-$168 million (OE-, NGC-$481.7 billion, TE-$90 million NGC-$486 million, TE-$26 million)) for replacement power costs incurred during an outage after an initial 20-week26-week waiting period. Members of NEIL I pay annual premiums and are subject to assessments if losses exceed the accumulated funds available to the insurer. FirstEnergy’s present maximum aggregate assessment for incidents at any covered nuclear facility occurring during a policy year would be approximately $3$13 million (NGC- (OE-$3 million)1 million, NGC-$12 million, and TE-less than $1 million).

FirstEnergy is insured as to its respective nuclear interests under property damage insurance provided by NEIL to the operating company for each plant. Under these arrangements, up to $2.8$2.8 billion of coverage for decontamination costs, decommissioning


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costs, debris removal and repair and/or replacement of property is provided. FirstEnergy pays annual premiums for this coverage and is liable for retrospective assessments of up to approximately $60$66 million (OE-$6 million, NGC-$5157 million, TE-$2 million, Met Ed, Penelec, and JCP&L-&L-less than $1 million in total) each) during a policy year.

FirstEnergy intends to maintain insurance against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of FirstEnergy’s plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by FirstEnergy’s insurance policies, or to the extent such insurance becomes unavailable in the future, FirstEnergy would remain at risk for such costs.

The NRC requires nuclear power plant licensees to obtain minimum property insurance coverage of $1.1 billion or the amount generally available from private sources, whichever is less. The proceeds of this insurance are required to be used first to ensure that the licensed reactor is in a safe and stable condition and can be maintained in that condition so as to prevent any significant risk to the public health and safety. Within 30 days of stabilization, the licensee is required to prepare and submit to the NRC a cleanup plan for approval. The plan is required to identify all cleanup operations necessary to decontaminate the reactor sufficiently to permit the resumption of operations or to commence decommissioning. Any property insurance proceeds not already expended to place the reactor in a safe and stable condition must be used first to complete those decontamination operations that are ordered by the NRC. FirstEnergy is unable to predict what effect these requirements may have on the availability of insurance proceeds.
(B)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 December 31, 2009, outstanding guarantees and other assurances aggregated approximately $4.2 billion, consisting of parental guarantees - $1.0 billion, subsidiaries’ guarantees - $2.6 billion, surety bonds - $0.1 billion and LOCs - $0.5 billion.

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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 guaranteescredit support 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 include provisions for parent guarantees, surety bonds and/or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claimLOCs to be satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees of $0.4 billion (included in the $1.0 billion discussed above) as of December 31, 2009 would increase amounts otherwise payableissued by FirstEnergy to meeton behalf of one or more of its obligations incurred in connection with financings and ongoing energy and energy-related activities.

While these types of guaranteessubsidiaries. Additionally, certain contracts may contain collateral provisions that are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgradecontingent upon either FirstEnergy's or “material adverse event,” the immediate posting of cash collateral, provision of an LOC or accelerated payments may be required of the subsidiary. 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. As a result, FirstEnergy may be required to post up to $48 million of collateral. Moody's and Fitch affirmed the ratings and stable outlook of FirstEnergy and its subsidiaries on February 11, 2010. ratings.
As of December 31, 2009, FirstEnergy's maximum exposure under these collateral provisions was $648 million,2011, outstanding guarantees and other assurances aggregated approximately $3.7 billion, consisting primarily of $43 million due to “material adverse event” contractual clauses, $98 million due to an acceleration of payment or funding obligation,parental guarantees ($0.9 billion), subsidiaries’ guarantees ($2.5 billion), surety bonds and $507 million due to a below investment grade credit rating including the $48 million related to the credit rating downgrade by S&P on February 11, 2010. 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 $807 million, consisting of $51 million due to “material adverse event” contractual clauses, $98 million related to an acceleration of payment or funding obligation, and $658 million due to a below investment grade credit rating.LOCs ($0.3 billion).

Most of FirstEnergy'sFirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $101$151 millionprovide 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.
While the types of guarantees discussed above are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a senior unsecured credit rating downgrade to below S&P's BBB- and Moody's Baa3 and lower, or a “material adverse event,” the immediate posting of collateral or accelerated payments may be required of the subsidiary. As ofDecember 31, 2011, FirstEnergy’s exposure to additional credit contingent contractual obligations was$636 million, as shown below:
Collateral Provisions FES AE Supply Utilities Total
  (In millions)
Credit rating downgrade to below investment grade (1)
 $468
 $8
 $57
 $533
Material adverse event (2)
 31
 60
 12
 103
Total $499
 $68
 $69
 $636
(1)
Includes $205 million and $47 million that are also considered accelerations of payment or funding obligations for FES and the Utilities, respectively.
(2)
Includes $31 million that is also considered an acceleration of payment or funding obligation at FES.

In addition to guarantees and surety bonds, FES’Certain bilateral non-affiliate contracts including power contracts with affiliates awarded through competitive bidding processes, typicallyentered into by the Competitive Energy Services segment contain margining provisions whichthat require the posting of cash or LOCs in amounts determined by future power price movements.collateral. Based on FES’FES' and AE Supply's power portfolioportfolios exposure as of December 31, 2009,2011, FES and forward prices asAE Supply have posted collateral of that date, FES had $179$88 million outstanding in margining accounts. Under a hypothetical adverse change in forward prices (95% confidence level change in forward prices over a one year time horizon), FES would be required to post an additional $129 million.and$1 million, respectively. Depending on the volume of forward contracts entered and future price movements, higher amounts for margining could be required.

Not included in the preceding information is potential collateral arising from the PSAs between FES couldor AE Supply and affiliated utilities in the Regulated Distribution Segment. As of December 31, 2011, neither FES nor AE Supply had any collateral posted with their affiliates. In the event of a senior unsecured credit rating downgrade to below S&P's BB- or Moody's Ba3, FES and AE Supply would be required to post higher amounts for margining.$49 millionand$24 million, respectively.

In July 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases (see Note 7). 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’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 willwould have claims against each of FES, FGCO and NGC, regardless of whether their primary obligor is FES, FGCO or NGC.


(C)ENVIRONMENTAL MATTERS
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Signal Peak and Global Rail are borrowers under a $350 million syndicated two-year senior secured term loan facility due in October 2012. FirstEnergy, together with WMB Loan Ventures, LLC and WMB Loan Ventures II, LLC, the entities that previously shared ownership in the borrowers with FEV, have provided a guaranty of the borrowers' obligations under the facility. On October 18, 2011, FEV sold a portion of its ownership interest in Signal Peak and Global Rail (see Note 8, Variable Interest Entities). Following the sale, FirstEnergy, WMB Loan Ventures, LLC and WMB Loan Ventures II, LLC, together with Global Mining Group, LLC and Global Holding will continue to guarantee the borrowers' obligations until either the facility is replaced with non-recourse financing (no later than June 30, 2012) or replaced with appropriate recourse financing no earlier than September 4, 2012, that provides for separate guarantees from each owner in proportion with each equity owner's percentage ownership in the joint venture. In addition, FEV, Global Mining Group, LLC and Global Holding, the entities that own direct and indirect equity interests in the borrowers, have pledged those interests to the lenders under the current facility as collateral.
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'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 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.

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Clean Air ActCAA Compliance

FirstEnergy is required to meet federally-approved SO2 and NOx emissions regulations.regulations under the CAA. FirstEnergy complies with SO2and NOx reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, combustion controls and post-combustion controls, generating more electricity from lower or non-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 SOpenalties.2
 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.

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

In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W. H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case and seven other similar cases are referred to as the NSR cases. OE’s and Penn’s settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation was approved by the Court on July 11, 2005. This settlement agreement, in the form of a consent decree, requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices or repowering and provides for stipulated penalties for failure to install and operate such pollution controls or complete repowering in accordance with that agreement. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree, including repowering Burger Units 4 and 5 for biomass fuel consumption, are currently estimated to be $399 million for 2010-2012.

In October 2007, PennFuture and three of its members filed a citizen suit under the federal CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations, in the United States District Court for the Western District of Pennsylvania. In July 2008,three additional complaints were filed against FGCO in the U.S. District Court for the Western District of Pennsylvania seeking damages based on air emissions from the coal-fired Bruce Mansfield Plant air emissions. In addition to seeking damages, two Plant.Twoof the threethese complaints also seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”,manner,” one being a complaint filed on behalf oftwenty-oneindividuals and the other being a class action complaint seeking certification as a class action with theeightnamed plaintiffs as the class representatives. On October 16, 2009, a settlement reached with PennFuture and one of the three individual complainants was approved by the Court, which dismissed the claims of PennFuture and of the settling individual. The other two non-settling individuals are now represented by counsel handling the three cases filed in July 2008. FGCO believes thosethe claims are without merit and intends to defend itself against the allegations made in those threethese 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.

In December 2007, the statestates of New Jersey and Connecticut filed a CAA citizen suitsuits in 2007 alleging NSR violations at the coal-fired Portland Generation Station against Reliant (theGenOn Energy, Inc. (formerly RRI Energy, Inc. and the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU 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 underin violation of the CAA'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. Met-Ed filed a Motion to DismissIn September 2009, the claims in New Jersey’s Amended Complaint and Connecticut’s Complaint in February and September of 2009, respectively. The Court granted Met-Ed's motion to dismiss New Jersey’sJersey's and Connecticut’sConnecticut's claims for injunctive relief against Met-Ed, but denied Met-Ed’sMet-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 allowand from Sithe Energy, and Met-Ed is unable to predict the states to prove either thatoutcome of this matter or estimate the applicationpossible loss or range of the discovery rule or the doctrine of equitable tolling bars application of the statute of limitations.loss.
In January 2009, the EPA issued a NOV to ReliantGenOn Energy, Inc. alleging NSR violations at the coal-fired 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 2009, NOV also alleged NSR violations at the Keystone and Shawville Stationscoal-fired plants 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.

matter or estimate the possible loss or range of loss.
234In each of May and September 2010, New Jersey submitted interstate pollution transport petitions seeking to reduce Portland Generating Station air emissions under section 126 of the CAA. Based on the September 2010 petition, the EPA has finalized emissions limits and compliance schedules to reduce SO2air emissions by approximately 81% at the Portland Station by January 6, 2015. New Jersey's May 2010 petition is still under consideration by the EPA.

In June 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. alleging that "modifications"“modifications” at the coal-fired Homer City Power StationPlant occurred sincefrom 1988 to the present without preconstruction NSR or permitting underin violation of the CAA's PSD program. In May 2010, the EPA issued a second NOV to Mission, Energy isPenelec, NYSEG and others that have had an ownership interest in Homer City containing in all material respects allegations identical to those included in the June 2008 NOV. In January 2011, the DOJ filed a complaint against Penelec in the U.S. District Court for the Western District of Pennsylvania seeking indemnification frominjunctive relief against Penelec based on alleged “modifications” at Homer City between 1991 to 1994 without preconstruction NSR permitting in violation of the CAA's PSD and Title V permitting programs. The complaint was also filed against the former co-owner, (along withNYSEG, and various current owners of Homer City, including EME Homer City Generation L.P. and affiliated companies, including Edison International. In addition, the Commonwealth of Pennsylvania and the States of New Jersey and New York State Electricintervened and Gas Company)have filed separate complaints regarding Homer City seeking injunctive relief and operatorcivil penalties. In January 2011, another complaint was filed against Penelec and the other entities described above in the U.S. District Court for the Western District of Pennsylvania seeking damages based on Homer City's air emissions as well as certification as a class action and to enjoin Homer City from operating except in a “safe, responsible, prudent and proper manner.” In October 2011, the Court dismissed all of the Homer City Power Station priorclaims with prejudice of the U.S. and the Commonwealth of Pennsylvania and the States of New Jersey and New York and all of the claims of the private parties,


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without prejudice to its salere-file state law claims in 1999. The scopestate court, against all of Penelec’s indemnity obligationthe defendants, including Penelec.In December 2011, the U.S., the Commonwealth of Pennsylvania and the States of New Jersey and New York all filed notices appealing to the Third Circuit Court of Appeals. Penelec believes the claims are without merit and from Mission Energy is disputed. Penelecintends to defend itself against the allegations made in these complaints, but, at this time, is unable to predict the outcome of this matter.matter or estimate the loss or possible range of loss. Mission is seeking indemnification from NYSEG and Penelec, the co-owners of Homer City prior to its sale in 1999. On February 13, 2012, the Sierra Club notified the current owner and operator of Homer City, Homer City OL1-OL8 LLC and EME Homer City Generation L.P., that it intends to file a CAA citizen suit regarding its Title V permit and SO2 emissions from the Homer City Plant.

In August 2009, the EPA issued a Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, including the PSD, NNSR and Title V regulations, at the Eastlake, Lakeshore, Bay Shore and Ashtabula generatingcoal-fired plants. The EPA’sEPA'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. In September 2009, FGCO also received an informationa request pursuant to Section 114(a) of the CAA requestingfor 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 plantPlant may constitute a major modification under the NSR provisionprovisions of the CAA. On December 23,Later in 2009, FGCO also received another information request regarding emission projections for the Eastlake generating plantPlant. In June 2011, EPA issued another Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, specifically opacity limitations and requirements to continuously operate opacity monitoring systems at the Eastlake, Lakeshore, Bay Shore and Ashtabula coal-fired plants. Also, in June 2011, FirstEnergy received an information request pursuant to Sectionsection 114(a) of the CAA.CAA for certain operating, maintenance and planning information, among other information regarding these plants. FGCO intends to comply with the CAA, including EPA’sthe EPA's information requests but, at this time, is unable to predict the outcome of this matter. A June 2006 findingmatter or estimate the possible loss or range 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.loss.

In August 2008, FirstEnergy2000, AE received aan information request from the EPA for information pursuant to Sectionsection 114(a) of the CAA for certain operatingfrom the EPA requesting that it provide information and documentation relevant to the operation and maintenance information regarding its formerly-owned Avon Lakeof the followingtencoal-fired plants, which collectively include22electric generation units: Albright, Armstrong, Fort Martin, Harrison, Hatfield's Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Niles generating plants, as well as a copy of a nearly identical request directed to the current owner, Reliant Energy, to allow the EPAWillow Island to determine whether these generating sources are complyingcompliance with the NSR provisions under the CAA, which can require the installation of the CAA. FirstEnergy intendsadditional air emission control equipment when a major modification of an existing facility results in an increase in emissions. AE has provided responsive information to fully comply with the EPA’s informationthis and a subsequent request but at this time, is unable to predict the outcome of this matter.matter or estimate the possible loss or range of loss.
In May 2004, AE, AE Supply, MP and WP received a Notice of Intent to Sue Pursuant to CAA §7604 from the Attorneys General of New York, New Jersey and Connecticut and from the PA DEP, alleging that Allegheny performed major modifications in violation of the PSD provisions of the CAA at the following West Virginia coal-fired generation units: Albright Unit 3; Fort Martin Units 1 and 2; Harrison Units 1, 2 and 3; Pleasants Units 1 and 2 and Willow Island Unit 2. The Notice also alleged PSD violations at the Armstrong, Hatfield's Ferry and Mitchell coal-fired plants in Pennsylvania and identifies PA DEP as the lead agency regarding those facilities. In September 2004, AE, AE Supply, MP and WP received a separate Notice of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.
In June 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed suit against AE, AE Supply, MP, PE and WP in the United States District Court for the Western District of Pennsylvania alleging, among other things, that Allegheny performed major modifications in violation of the CAA and the Pennsylvania Air Pollution Control Act at the coal-fired Hatfield's Ferry, Armstrong and Mitchell Plants in Pennsylvania. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. A non-jury trial on liability only was held in September 2010. Plaintiffs filed their proposed findings of fact and conclusions of law in December 2010, Allegheny made its related filings in February 2011 and plaintiffs filed their responses in April 2011. The parties are awaiting a decision from the District Court, but there is no deadline for that decision and we are unable to predict the outcome or estimate the possible loss or range of loss.
In September 2007, Allegheny received a NOV from the EPA alleging NSR and PSD violations under the CAA, as well as Pennsylvania and West Virginia state laws at the coal-fired Hatfield's Ferry and Armstrong plants in Pennsylvania and the coal-fired Fort Martin and Willow Island plants in West Virginia.
FirstEnergy intends to vigorously defend against the CAA matters described above but cannot predict their outcomes or estimate the possible loss or range of loss.
State Air Quality Compliance
In early 2006, Maryland passed the Healthy Air Act, which imposes state-wide emission caps on SO2and NOx, requires mercury emission reductions and mandates that Maryland join the RGGI and participate in that coalition's regional efforts to reduce CO2emissions. On April 20, 2007, Maryland became the tenth state to join the RGGI. The Healthy Air Act provides a conditional exemption for the R. Paul Smith coal-fired plant for NOx, SO2and mercury, based on a 2006 PJM declaration that the plant is vital to reliability in the Baltimore/Washington DC metropolitan area. Pursuant to the legislation, the MDE passed alternate NOx and SO2limits for R. Paul Smith, which became effective in April 2009. However, R. Paul Smith is still required to meet the Healthy Air Act mercury reductions of80%which began in 2010. The statutory exemption does not extend to R. Paul Smith's CO2emissions. Maryland issued final regulations to implement RGGI requirements in February 2008.FourteenRGGI auctions have been held through the end of calendar year 2011. RGGI allowances are also readily available in the allowance markets, affording another mechanism by which to secure necessary allowances. On March 14, 2011, MDE requested PJM perform an analysis to determine if termination of operation at R. Paul Smith would adversely impact the reliability of electrical service in the PJM region under current system


248


conditions. On June 30, 2011, PJM notified MDE that termination of operation at R. Paul Smith would adversely impact the reliability of electrical service in the PJM region absent transmission system upgrades. On January 26, 2012, FirstEnergy announced that R. Paul Smith is among nine coal-fired plants it intends to retire by September 1, 2012, subject to review of reliability impacts by PJM. FirstEnergy is unable to predict the outcome of this matter or estimate the possible loss or range of loss.
In January 2010, the WVDEP issued a NOV for opacity emissions at the Pleasants coal-fired plant. In August 2011, FirstEnergy and WVDEP resolved the NOV through a Consent Order requiring installation of a reagent injection system to reduce opacity by September 2012.
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 NOXNOx and SO2 emissions intwophases (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 to2.5 milliontons annually and NOXNOx emissions to1.3 milliontons annually. CAIR was challenged inIn 2008, the U.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.” In September 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. In December 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, 2008Court's opinion. On July 10, 2009, the U.S.The 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“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's future cost of compliance with these regulations may be substantial and will depend, in part, on the action taken by the EPA in response to the Court’s ruling.

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,July 2011, the EPA finalized the CAMR, which provides a cap-and-trade programCSAPR, to reduce mercury replace CAIR,requiring reductions of NOx and SO2emissions from coal-firedintwo phases (2012 and 2014), ultimately capping SO2emissions in affected states to2.4 milliontons annually and NOx emissions to1.2 milliontons annually. CSAPR allows trading of NOx and SO2emission allowances between power plants located in two phases; initially, capping national mercury the same state and interstate trading of NOx and SO2emission allowances with some restrictions. On February 21, 2012, the EPA revised certain CASPR state budgets (for Florida, Louisiana, Michigan, Mississippi, Nebraska, New Jersey, New York, Texas, and Wisconsin and new unit set-asides in Arkansas and Texas), certain generating unit allocations (for some units in Alabama, Indiana, Kansas, Kentucky, Ohio and Tennessee) for NOx and SO2emissions at 38 tonsand delayed from 2012 to 2014 certain allowance penalties that could apply with respect to interstate trading of NOx and SO2emission allowances.On December 30, 2011, CSAPR was stayed by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the U.S. Court of Appeals for the District of Columbia. Columbia Circuit pending a decision on legal challenges raised in appeals filed by various stakeholders and scheduled to be argued before the Court on April 13, 2012. The Court ordered EPA to continue administration of CAIR until the Court resolves the CSAPR appeals. Depending on the outcome of these proceedings and how any final rules are ultimately implemented, FGCO's and AE Supply's future cost of compliance may be substantial and changes to FirstEnergy's operations may result.

During 2011, FirstEnergy recorded pre-tax impairment charges of approximately$6 million($1 millionfor FES and$5 millionfor AE Supply) for NOx emission allowances that were expected to be obsolete after 2011 and approximately$21 million($18 millionfor FES and$3 millionfor AE Supply) for excess SO2emission allowances in inventory that it expects will not be consumed in the future.
Hazardous Air Pollutant Emissions
On December 21, 2011, the EPA finalized the MATS to establish emission standards for mercury, hydrochloric acid and various metals for electric generating units. The MATS establishes emission limits for mercury, PM, and HCL for all existing and new coal-fired electric generating units effective in April 2015 and allows averaging of emissions from multiple units located at a single plant. Under the CAA, state permitting authorities can grant an additional compliance year through April 2016, as needed, including instances when necessary to maintain reliability where electric generating units are being closed. In addition, an EPA enforcement policy document contemplates up to an additional year to achieve compliance, through April 2017, under certain circumstances for reliability critical units. On January 26, 2012 and February 8, 2008,2012, FGCO, MP and AE Supply announced the Court vacated the CAMR, ruling that the EPA failedretirement by September 1, 2012 (subject to take the necessary steps to “de-list”a reliability review by PJM) of nine coal-fired power plants from its hazardous air pollutant program(Albright, Armstrong, Ashtabula, Bay Shore except for generating unit 1, Eastlake, Lake Shore, R. Paul Smith, Rivesville and therefore, could not promulgateWillow Island) with a cap-and-trade program. The EPA petitioned for rehearingtotal capacity of3,349megawatts (generating, on average, approximately ten percent of the electricity produced by the entire Court, which deniedcompanies over the petition in May 2008. In October 2008, the EPA (and an industry group) petitioned the U.S. Supreme Court for review of the Court’s ruling vacating CAMR. On February 6, 2009, the EPA movedpast three years) due to dismiss its petition for certiorari. On February 23, 2009, the Supreme Court dismissed the EPA’s petition and denied the industry group’s petition. On October 21, 2009, the EPA opened a 30-day comment period on a proposed consent decree that would obligate the EPA to propose MACT regulations for mercuryMATS and other hazardous air pollutants by March 16, 2011, andenvironmental regulations. In addition, MP will make a filing with the WVPSC to finalizeprovide them with information regarding the regulations by November 16, 2011. FGCO’sretirement of its plants. Depending on how the MATS are ultimately implemented, FirstEnergy's future cost of compliance with MACT regulationsMATS may be substantial and other changes to FirstEnergy's operations may result.
On February 24, 2012, PJM notified FirstEnergy of its preliminary analysis of the reliability impacts that may result from closure of the older competitive coal-fired generating units. PJM's preliminary analysis indicated that there would be significant reliability concerns that will depend onneed to be addressed. FirstEnergy intends to continue to actively engage in discussions with PJM regarding this notification, including the action taken by the EPA and on how any future regulations are ultimately implemented.

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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 December 23, 2009, the Supreme Courtpossible continued operation of Pennsylvania affirmed the Commonwealth Court of Pennsylvania ruling that Pennsylvania’s mercury rule is “unlawful, invalid and unenforceable” and enjoined the Commonwealth from continued implementation or enforcement of that rule.

certain plants.
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 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, in June 2009. Certain states, primarily the northeastern states participating in the RGGI and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.


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In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that required FirstEnergy to measure and report GHG emissions commencing in 2010. In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA's finding concludes that concentrations of several key GHGs increase the threat of climate change and may be regulated as “air pollutants” under the CAA. In April 2010, the EPA finalized new 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 would not be triggered for electric generating plants and other stationary sources until January 2, 2011, at the earliest. In May 2010, the EPA finalized new thresholds for GHG emissions that define when permits under the CAA's NSR program would be required. The EPA established an emissions applicability threshold of75,000tons per year of CO2equivalents effective January 2, 2011, for existing facilities under the CAA's PSD program.
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 man-made GHG, including CO2, emitted by developed countries by 2012. A December 2009 U.N. Climate Change Conference in Copenhagen did not reach a consensus on a successor treaty to the Kyoto Protocol, but did take note of the Copenhagen Accord, a non-binding political agreement whichthat recognized the scientific view that the increase in global temperature should be belowtwodegrees Celsius, includedCelsius; includes a commitment by developed countries to provide funds, approaching $30$30 billionover the next three years with a goal of increasing to $100$100 billionby 2020,2020; and establishedestablishes the “Copenhagen Green“Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. OnceTo the extent that 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 targets from 2020, while developing countries, including Brazil, China and India, would agree to take mitigation actions, subject to their domestic measurement, reporting and verification. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHGverification.A December 2011 U.N. Climate Change Conference 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 considerDurban, Africa, established a number of measures to regulate GHG emissions. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states, led by California, have coordinated effortsnegotiating process to develop regional strategiesa new post-2020 climate change protocol, called the “Durban Platform for Enhanced Action”. This negotiating process contemplates developed countries, as well as developing countries such as China, India, Brazil, and South Africa, to control emissions ofundertake legally binding commitments post-2020. In addition, certain GHGs.

On April 2, 2007,countries agreed to extend the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. In December 2009, the EPA released its final “Endangerment and Cause or Contribute FindingsKyoto Protocol for Greenhouse Gases under the Clean Air Act.” The EPA’s finding concludes that the atmospheric concentrations of several key GHG 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 GHG and hence to the threat of climate change. Although the EPA’s finding does not establish emission requirements for motor vehicles, such requirements are expected to occur through further rulemakings. Additionally, while the EPA’s endangerment findings do not specifically address stationary sources, including electric generating plants  EPA’s expected establishment of emission requirements for motor vehicles would be expected to support the establishment of future emission requirements by the EPA for stationary sources. In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that will require FirstEnergy to measure GHG emissionssecond commitment period, commencing in 20102013 and submit reports commencingexpiring in 2011. Also in September 2009, EPA proposed new thresholds for GHG emissions that define when CAA permits under the NSR and Title V operating permits programs would be required. EPA is proposing a major source emissions applicability threshold of 25,000 tons per year (tpy) of carbon dioxide equivalents (CO2e) for existing facilities under the Title V operating permits program and the Prevention of Significant Determination (PSD) portion of NSR. EPA is also proposing a significance level between 10,000 and 25,000 tpy CO2e to determine if existing major sources making modifications that result in an increase of emissions above the significance level would be required to obtain a PSD permit.2018 or 2020.

On September 21,In 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. 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. While FirstEnergy is notThe U.S. Supreme Court granted a partywrit of certiorari to either litigation, shouldreview the courtsdecision of appeals decisions be affirmed or not subjectedthe Second Circuit. On June 20, 2011, the U.S. Supreme Court reversed the Second Circuit but failed to further review, FirstEnergy and/or one or moreanswer the question of its subsidiaries could be named inthe extent to which actions making similar allegations.

for damages based on GHG emissions may remain viable. The Court remanded to the Second Circuit the issue of whether the CAA preempted state common law nuisance actions.
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 of its regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.

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Clean Water Act

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

On September 7,In 2004, the EPA established new performance standards under Section 316(b) of the Clean Water ActCWA for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). On January 26,In 2007, the United States Court of Appeals for the Second Circuit remandedinvalidated portions of the rulemaking dealing with impingement mortalitySection 316(b) performance standards and entrainment back to the EPA for further rulemaking and eliminatedhas taken 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. OnIn 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 ActCWA authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. On March 28, 2011, the EPA is developingreleased a new proposed regulation under Section 316(b) of the Clean Water Act consistent withCWA generally requiring fish impingement to be reduced to a12%annual average and studies to be conducted at the opinionsmajority of our existing generating facilities to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic life. On July 19, 2011, the Supreme Court andEPA extended the Court of Appeals which have created significant uncertainty aboutpublic comment period for the specific nature, scope and timing of thenew proposed Section 316(b) regulation by30days but stated its schedule for issuing a final performance standard.rule remains July 27, 2012. 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. Depending on the results of such studies and the EPA’sEPA'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 April 2011, the U.S. Attorney's Office in Cleveland, Ohio has advised FGCO that it is no longer considering prosecution under the Clean Water Act


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CWA 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. On August 5, 2011, EPA issued an information request pursuant to Sections 308 and 311 of the CWA for certain information pertaining to the oil spills and spill prevention measures at FirstEnergy facilities. FirstEnergy responded on October 10, 2011. On February 1, 2012, FirstEnergy executed a tolling agreement with the EPA extending the statute of limitations to July 31, 2012. FGCO does not anticipate any losses resulting from this matter to be material.
In May 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club filed a CWA citizen suit alleging violations of arsenic limits in the NPDES water discharge permit for the fly ash impoundments at the Albright Station seeking unspecified civil penalties and injunctive relief. The MP filed an answer on July 11, 2011, and a motion to stay the proceedings on July 13, 2011. On January 3, 2012, the Court denied MP's motion to dismiss or stay the CWA citizen suit but without prejudice to re-filing in the future. MP is unablecurrently seeking relief from the arsenic limits through WVDEP agency review.

In June 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club served a60-Day Notice of Intent required prior to filing a citizen suit under the CWA for alleged failure to obtain a permit to construct the fly ash impoundments at the Albright Plant.
FirstEnergy intends to vigorously defend against the CWA matters described above but, except as indicated above, cannot predict their outcomes or estimate the possible loss or range of loss.
Monongahela River Water Quality
In late 2008, the PA DEP imposed water quality criteria for certain effluents, including TDS and sulfate concentrations in the Monongahela River, on new and modified sources, including the scrubber project at the coal-fired Hatfield's Ferry Plant. These criteria are reflected in the current PA DEP water discharge permit for that project. AE Supply appealed the PA DEP's permitting decision, which would require it to incur estimated costs in excess of$150 millionin order to install technology to meet TDS and sulfate limits in the permit or negatively affect its ability to operate the scrubbers as designed. The permit has been independently appealed by Environmental Integrity Project and Citizens Coal Council, which seeks to impose more stringent technology-based effluent limitations. Those same parties have intervened in the appeal filed by AE Supply, and both appeals have been consolidated for discovery purposes. An order has been entered that stays the permit limits that AE Supply has challenged while the appeal is pending. A hearing on the parties' appeals was scheduled to begin in September 2011, however the Court stayed all prehearing deadlines on July 15, 2011 to allow the parties additional time to work out a settlement, and has rescheduled a hearing, if necessary, for July 2012. If these settlement discussions are successful, AE Supply anticipates that its obligations will not be material. AE Supply intends to vigorously pursue these issues, but cannot predict the outcome of these appeals or estimate the possible loss or range of loss.
In a parallel rulemaking, the PA DEP recommended, and in August 2010, the Pennsylvania Environmental Quality Board issued, a final rule imposing end-of-pipe TDS effluent limitations. FirstEnergy could incur significant costs for additional control equipment to meet the requirements of this matter.rule, although its provisions do not apply to electric generating units until the end of 2018, and then only if the EPA has not promulgated TDS effluent limitation guidelines applicable to such units.
In December 2010, PA DEP submitted its CWA 303(d) list to the EPA with a recommended sulfate impairment designation for an approximately68mile stretch of the Monongahela River north of the West Virginia border. In May 2011, the EPA agreed with PA DEP's recommended sulfate impairment designation. PA DEP's goal is to submit a final water quality standards regulation, incorporating the sulfate impairment designation for EPA approval by May, 2013. PA DEP will then need to develop a TMDL limit for the river, a process that will take approximatelyfiveyears. Based on the stringency of the TMDL, FirstEnergy may incur significant costs to reduce sulfate discharges into the Monongahela River from the coal-fired Hatfield's Ferry and Mitchell Plants in Pennsylvania and the coal-fired Fort Martin Plant in West Virginia.
In October 2009, the WVDEP issued the water discharge permit for the Fort Martin Plant. Similar to the Hatfield's Ferry water discharge permit, the Fort Martin permit imposes effluent limitations for TDS and sulfate concentrations. The permit also imposes temperature limitations and other effluent limits for heavy metals that are not contained in the Hatfield's Ferry water discharge permit. Concurrent with the issuance of the Fort Martin permit, WVDEP also issued an administrative order that sets deadlines for MP to meet certain of the effluent limits that are effective immediately under the terms of the permit. MP appealed the Fort Martin permit and the administrative order. The appeal included a request to stay certain of the conditions of the permit and order while the appeal is pending, which was granted pending a final decision on appeal and subject to WVDEP moving to dissolve the stay. The appeals have been consolidated. MP moved to dismiss certain of the permit conditions for the failure of the WVDEP to submit those conditions for public review and comment during the permitting process. An agreed-upon order that suspends further action on this appeal, pending WVDEP's release for public review and comment on those conditions, was entered on August 11, 2010. The stay remains in effect during that process. The current terms of the Fort Martin permit would require MP to incur significant costs or negatively affect operations at Fort Martin. Preliminary information indicates an initial capital investment in excess of the capital investment that may be needed at Hatfield's Ferry in order to install technology to meet the TDS and sulfate limits in the Fort Martin permit, which technology may also meet certain of the other effluent limits in the permit. Additional technology may be needed to meet certain other limits in the permit. MP intends to vigorously pursue these issues but cannot predict the outcome of these appeals or estimate the possible loss or range of loss.


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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's evaluation of the need for future regulation. In February 2009, the EPA requested comments from the states on options for regulating coal combustion wastes,residuals, including regulationwhether they should be regulated as hazardous or non-hazardous waste or regulation as a hazardous waste. In March and June 2009, the EPA requested information from FGCO’s Bruce Mansfield Plant regarding the management of coal combustion wastes.
In December 2009, EPA provided to FGCO the findings of its review of the Bruce Mansfield Plant’s coal combustion waste management practices.  EPA observed that the waste management structures and the Plant “appeared to be well maintained and in good working order” and recommended only that FGCO “seal and maintain all asphalt surfaces.” On December 30, 2009, in an advancedadvance notice of public rulemaking, the EPA saidasserted that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. Additional regulationsIn May 2010, the EPA proposedtwooptions for additional regulation of fossil-fuelcoal combustion residuals, including the option of regulation as a special waste productsunder the EPA's hazardous waste management program which could have a significant impact on ourthe management, beneficial use and disposal of coal ash. FGCO'scombustion residuals. FirstEnergy's future cost of compliance with any coal combustion wasteresiduals regulations whichthat 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. Compliance with those regulations could have an adverse impact on FirstEnergy's results of operations and financial condition.
LBR CCB impoundment is expected to run out of disposal capacity for disposal of CCBs from the BMP between 2016 and 2018. BMP is pursuing several CCB disposal options.
The UtilitiesCertain of our 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 ofDecember 31, 2009,2011, based on estimates of the total costs of cleanup, the Utilities'Utility Registrants' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay.Total liabilities of approximately $101$106 million (JCP(JCP&L - $74$70 million, TE - $1$1 million, CEI - $1$1 million, FGCO - $1$1 millionand FirstEnergyFE - $24$33 million) have been accrued throughDecember 31, 2009.2011. Included in the total are accrued liabilities of approximately $67$63 millionfor 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.

On July 11, 2011, FirstEnergy was found to be a potentially responsible party under CERCLA, indirectly liable for a portion of past and future clean-up costs at certain legacy MGP sites, estimated to total approximately$59 million. FirstEnergy recognized an additional expense of$29 millionduring the second quarter of 2011;$30 millionhad previously been reserved prior to 2011.FirstEnergy determined that it is reasonably possible that it or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the possible losses or range of losses cannot be determined or reasonably estimated at this time.
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(D)   OTHER LEGAL PROCEEDINGS

Power Outages and Related Litigation

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

After various motions, rulings and appeals, the Plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, strict product liability and punitive damages were dismissed, leaving only the negligence and breach of contract causes of actions. The class was decertified twice by the trial court, and appealed both times by the Plaintiffs, with the results being that: (1)On July 29, 2010, the Appellate Division limited the class only to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation which resulted in planned and unplanned outages in the area during a 2-3 day period, and (2) in March 2007, the Appellate Division remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. On March 31, 2009, the trial court again granted JCP&L’s motion to decertify the class. On April 20, 2009, the Plaintiffs filed a motion for leave to take an interlocutory appeal to the trial court's decision to decertify the class, which was granted by the Appellate Division on June 15, 2009. Plaintiffs filed their appellate brief on August 25, 2009, and JCP&L filed an opposition brief on September 25, 2009. On or about October 13, 2009, Plaintiffs filed their reply brief in further support of their appeal ofupheld the trial court's decision decertifying the class. In November 2010, the Supreme Court issued an order denying Plaintiffs' motion for leave to appeal. The Appellate Division heard oral argument on January 5, 2010, beforeCourt's order effectively ends the attempt to certify the class, and leaves only9plaintiffs to pursue their respective individual claims. The matter was referred back to the lower court, which set a three-judge panel. JCP&Ltrial date for February 13, 2012, for the remaining individual plaintiffs. Plaintiffs have accepted an immaterial amount in final settlement of all matters and the settlement documentation is awaiting the Court’s decision.

being finalized for execution by all parties.
Nuclear Plant Matters

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

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As ofDecember 31, 2009,2011, FirstEnergy had approximately $1.9$2 billioninvested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy provided an additional $80 million parental guarantee associated with the funding of decommissioning costs for these units and indicated that it planned to contribute an additional $80 million to these trusts by 2010. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy’s nuclear decommissioning trustsFirstEnergy's NDT fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy’sFirstEnergy's obligation to fund the trusts may increase. Disruptions in the capital markets and itstheir effects on particular businesses and the economy in generalcould also affectsaffect the values of the NDT. On March 28, 2011, FENOC submitted its biennial report on nuclear decommissioning trusts. On June 18, 2009,funding to the NRC informed FENOC that its review tentatively concluded thatNRC. This submittal identified a total shortfall existed in the decommissioning trust fund for Beaver Valley Unit 1. On November 24, 2009, FENOC submitted a revisednuclear decommissioning funding calculation using the NRC formula method based on the renewed license for Beaver Valley Unit 1 and Perry of approximately$92.5 million. By letter dated December 29, 2011, FENOC informed the NRC staff that it had increased the parental guarantee to$95 million.
In January 2004, subsidiaries of FirstEnergy filed a lawsuit in the U.S. Court of Federal Claims seeking damages in connection with costs incurred at the Beaver Valley, Davis-Besse and Perry nuclear facilities as a result of the DOE's failure to begin accepting spent nuclear fuel on January 31, 1998. DOE was required to begin accepting spent nuclear fuel by the Nuclear Waste Policy Act


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(42 USC 10101 et seq) and the contracts entered into by the DOE and the owners and operators of these facilities pursuant to the Act.In January 2012, the applicable FirstEnergy affiliates reached a$48 millionsettlement of these claims.

In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse operating license for an additional twenty years, until 2037. By an order dated April 26, 2011, a NRC ASLB granted a hearing on the Davis-Besse license renewal application to a group of petitioners. By this order, the ASLB also admitted two contentions challenging whether FENOC's Environmental Report adequately evaluated (1) a combination of renewable energy sources as alternatives to the renewal of Davis-Besse's operating license, and (2) severe accident mitigation alternatives at Davis-Besse. On May 6, 2011, FENOC filed an appeal with the NRC from the order granting a hearing on the Davis-Besse license renewal application.On January 10, 2012, intervenors petitioned the ASLB for a new contention on the cracking of the Davis-Besse shield building discussed below.
On October 1, 2011, Davis-Besse was safely shut down for a scheduled outage to install a new reactor vessel head and complete other maintenance activities. The new reactor head, which extended operations until 2036. FENOC’s submittal demonstrated that therereplaced a head installed in 2002, enhances safety and reliability, and features control rod nozzles made of material less susceptible to cracking. On October 10, 2011, following opening of the building for installation of the new reactor head, a sub-surface hairline crack was a de minimis shortfall. identified in one of the exterior architectural elements on the shield building. These elements serve as architectural features and do not have structural significance. During investigation of the crack at the shield building opening, concrete samples and electronic testing found similar sub-surface hairline cracks in most of the building's architectural elements. FENOC's investigation also identified other indications. Included among them were sub-surface hairline cracks in the upper portion of the shield building (above elevation 780') and in the vicinity of the main steam line penetrations.A team of industry-recognized structural concrete experts and Davis-Besse engineers has determined these conditions do not affect the facility's structural integrity or safety.
On December 2, 2011, the NRC issued a CAL which concluded that FENOC provided "reasonable assurance that the shield building remains capable of performing its safety functions." The CAL imposed a number of commitments from FENOC including, submitting a root cause evaluation and corrective actions to the NRC by February 28, 2012, and further evaluations of the shield building. On February 27, 2012, FENOC sent the root cause evaluation to the NRC. Finally, the CAL also stated that the NRC was still evaluating whether the current condition of the shield building conforms to the plant's licensing basis. On December 6, 2011, the Davis-Besse plant returned to service.
By letter dated August 25, 2011, the NRC made a final significance determination (white) associated with a violation that occurred during the retraction of a source range monitor from the Perry reactor vessel. The NRC also placed Perry in the degraded cornerstone column (Column 3) of the NRC's Action Matrix governing the oversight of commercial nuclear reactors. As a result, the NRC staff will conduct several supplemental inspections, culminating in an inspection using Inspection Procedure 95002 to determine if the root cause and contributing causes of risk significant performance issues are understood, the extent of condition has been identified, whether safety culture contributed to the performance issues, and if FENOC's corrective actions are sufficient to address the causes and prevent recurrence.
In light of the impacts of the earthquake and tsunami on the reactors in Fukushima, Japan, the NRC conducted inspections of emergency equipment at U.S. reactors. The NRC also established a Near-Term Task Force to review its processes and regulations in light of the incident, and, on July 12, 2011, the Task Force issued its report of recommendations for regulatory changes. On October 18, 2011, the NRC approved the Staff recommendations, and directed the Staff to implement its near-term recommendations without delay. Ultimately, the adoption of the Staff recommendations on near-term actions is likely to result in additional costs to implement plant modifications and upgrades required by the regulatory process over the next several years, which costs are likely to be material.

On February 16, 2012, the NRC issued a request for information to the licensed operators of 11 2009,nuclear power plants, including Beaver Valley Power Station Units 1 and 2, with respect to the NRC’s reviewmodeling of FirstEnergy’s methodologyfuel performance as it relates to "thermal conductivity degradation," which is the potential in older fuel for reduced capacity to transfer heat that could potentially change its performance during various accident scenarios, including loss of coolant accidents. The request for information indicated that this phenomenon has not been accounted for adequately in performance models for the fundingfuel developed by the fuel manufacturer. The NRC is requesting that FENOC provide an analysis to demonstrate that the NRC regulations are being met. Absent that demonstration, the request indicates that the NRC may consider imposing restrictions on reactor operating limits until the issue is satisfactorily resolved.
ICG Litigation
On December 28, 2006, AE Supply and MP filed a complaint in the Court of decommissioningCommon Pleas of this facility concluded that there was reasonable assuranceAllegheny County, Pennsylvania against ICG, Anker WV, and Anker Coal. Anker WV entered into a long term Coal Sales Agreement with AE Supply and MP for the supply of adequate decommissioning funding atcoal to the Harrison generating facility. Prior to the time permanent termination of operationstrial, ICG was dismissed as a defendant by the Court, which issue can be the subject of a future appeal. As a result of defendants' past and continued failure to supply the contracted coal, AE Supply and MP have incurred and will continue to incur significant additional costs for purchasing replacement coal. A non-jury trial was held from January 10, 2011 through February 1, 2011. At trial, AE Supply and MP presented evidence that they have incurred in excess of$80 millionin damages for replacement coal purchased through the end of 2010 and will incur additional damages in excess of$150 millionfor future shortfalls. Defendants primarily claim that their performance is expected. FirstEnergy continuesexcused under a force majeure clause in the coal sales agreement and presented evidence at trial that they will continue to evaluatenot provide the statuscontracted yearly tonnage amounts. On May 2, 2011, the court entered a verdict in favor of its funding obligationsAE Supply and MP for$104 million($90 millionin future damages and$14 millionfor replacement coal / interest). Post-trial filings occurred in May 2011, with Oral Argument on June 28,


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2011. On August 25, 2011, the decommissioningAllegheny County Court denied all Motions for Post-Trial relief and the May 2, 2011 verdict became final. On August 26, 2011, ICG posted bond and filed a Notice of these nuclear facilities.Appeal. Briefing on the Appeal is concluded with oral argument expected in May or June of 2012. AE Supply and MP intend to vigorously pursue this matter through appeal.

Other Legal Matters

In February 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 reduction 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 approved by the PUCO. In March 2010, the named-defendant companies filed a motion to dismiss the case due to the lack of jurisdiction of the court of common pleas. The court granted the motion to dismiss on September 7, 2010. The plaintiffs appealed the decision to the Court of Appeals of Ohio.On October 21, 2011, the Court of Appeals rendered its decision affirming the dismissal of the Complaint by the Court of Common Pleas on all counts except for one relating to an allegation of fraud. The Companies timely filed a notice of appeal on December 5, 2011 with the Supreme Court of Ohio challenging this one aspect of the Court of Appeals opinion. The Supreme Court of Ohio has not yet acted on the appeal.

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.under Note 15, Regulatory Matters.

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

238

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. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss and if such estimate can be made. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced above, matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

16.  SEGMENT INFORMATION

Financial information for each of FirstEnergy’s reportable segments is presented in the following 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 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 2008 and 2007 have been reclassified to conform to the 2009 presentation.

The energy delivery services segment transmits 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 PLR 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.

The competitive energy services segment supplies electric power to end-use customers through retail and wholesale arrangements, including associated company power sales to meet all or a portion of the PLR and default service requirements of FirstEnergy's Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Maryland and Michigan. This business segment owns or leases and operates 19 generating facilities with a net demonstrated capacity of 13,710 MWs 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.

239

The other segment contains corporate items and other businesses that are below the quantifiable threshold for separate disclosure as a reportable segment.

  Energy  Competitive          
  Delivery  Energy     Reconciling    
Segment Financial Information Services  Services  Other  Adjustments  Consolidated 
  (In millions) 
2009               
External revenues $11,144  $1,888  $37  $(119) $12,950 
Internal revenues*  -   2,843   -   (2,826)  17 
Total revenues  11,144   4,731   37   (2,945)  12,967 
Depreciation and amortization  1,464   270   10   11   1,755 
Investment income  139   121   -   (56)  204 
Net interest charges  469   106   8   265   848 
Income taxes  290   345   (265)  (125)  245 
Net income  435   517   257   (219)  990 
Total assets  22,978   10,584   607   135   34,304 
Total goodwill  5,551   24   -   -   5,575 
Property additions  750   1,262   149   42   2,203 
                     
2008                    
External revenues $12,068  $1,571  $72  $(84) $13,627 
Internal revenues  -   2,968   -   (2,968)  - 
Total revenues  12,068   4,539   72   (3,052)  13,627 
Depreciation and amortization  1,154   243   4   13   1,414 
Investment income  171   (34)  6   (84)  59 
Net interest charges  408   108   2   184   702 
Income taxes  611   314   (53)  (95)  777 
Net income  916   472   116   (165)  1,339 
Total assets  23,025   9,559   539   398   33,521 
Total goodwill  5,551   24   -   -   5,575 
Property additions  839   1,835   176   38   2,888 
                     
2007                    
External revenues $11,322  $1,468  $39  $(27) $12,802 
Internal revenues  -   2,901   -   (2,901)  - 
Total revenues  11,322   4,369   39   (2,928)  12,802 
Depreciation and amortization  899   204   4   26   1,133 
Investment income  241   16   1   (138)  120 
Net interest charges  446   152   4   141   743 
Income taxes  643   330   4   (94)  883 
Net income  965   495   12   (160)  1,312 
Total assets  23,826   7,669   303   513   32,311 
Total goodwill  5,583   24   -   -   5,607 
Property additions  814   740   21   58   1,633 

 *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.
240

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.

Products and Services

    
  Electricity 
Year
 
Sales
 
  (In millions) 
2009 $12,032 
2008  12,693 
2007  11,944 
17.NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

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

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

In 2010, the FASB amended the Fair Value Measurements and Disclosures Topic of the FASB Accounting Standards Codification to require additional disclosures about 1) transfers of Level 1 and Level 2 fair value measurements, including the reason for transfers, 2) purchases, sales, issuances and settlements in the roll forward of activity in Level 3 fair value measurements, 3) additional disaggregation to include fair value measurement disclosures for each class of assets and liabilities and 4) disclosure of inputs and valuation techniques used to measure fair value for both recurring and nonrecurring fair value measurements.  The amendment is effective for fiscal years beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances and settlements in the roll forward of activity in Level 3 fair value measurements, which is effective for fiscal years beginning after December 15, 2010.  FirstEnergy does not expect this standard to have a material effect upon its financial statements.

18.17. TRANSACTIONS WITH AFFILIATED COMPANIES

FES’ and the Registrant Utilities’ operating revenues, operating expenses, investment income and interest expenseexpenses include transactions with affiliated companies. These affiliated company transactions include PSAsaffiliated company power sales agreements between FESFirstEnergy's competitive and the Utilities,regulated companies, support service billings, from FESC and FENOC, interest on associatedaffiliated company notes including the money pools and other transactions (see Note 7).transactions.

The Ohio Companies had a PSA with FESFirstEnergy's competitive companies provide power through December 31, 2009affiliated company power sales to meet their PLRa portion of the Ohio and Pennsylvania Companies' POLR and default service obligations.requirements. Prior to 2011, Met-Ed and Penelec havehad a partial requirement PSA with FES to meet a portion of their PLR and default service obligations (see Note 9). FES is incurring interest expense through FGCO and NGC on associated company notes payable to the Ohio Companies and Penn related to the 2005 intra-system generation asset transfers.POLR obligations. The primary affiliated company transactions for FES and the Registrant Utilities forduring the three years ended December 31, 20092011 are as follows:

Affiliated Company Transactions —              
2011 FES OE CEI TE JCP&L Met-Ed Penelec
  (In millions)
Revenues:              
Electric sales to affiliates $752
 $200
 $2
 $55
 $—
 $—
 $—
Ground lease with ATSI —
 12
 7
 2
 —
 —
 —
Other 80
 1
 3
 —
 —
 10
 —
Expenses:              
Purchased power from affiliates 252
 287
 143
 94
 —
 143
 208
Fuel 37
 —
 —
 —
 —
 —
 —
Support services 655
 130
 51
 53
 90
 53
 54
Investment Income:              
Interest income from affiliates —
 —
 —
 9
 —
 —
 —
Interest income from FE 2
 —
 —
 —
 —
 —
 —
Interest Expense:              
Interest expense to affiliates 5
 4
 10
 1
 4
 3
 2
Interest expense to FE 1
 —
 —
 —
 1
 1
 1

241
Affiliated Company Transactions - 2009 FES  OE  CEI  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
Revenues:                     
Electric sales to affiliates
 $2,826  $187  $-  $35  $-  $-  $- 
Ground lease with ATSI  -   12   7   2   -   -   - 
Other*  17   -   -   -   -   -   - 
                             
Expenses:
                            
Purchased power from affiliates
  222   991   735   393   -   365   342 
Support services
  563   140   60   55   85   52   53 
                             
Investment Income:
                            
Interest income from affiliates
  -   15   -   17   -   -   - 
Interest income from FirstEnergy
  4   1   -   -   -   -   - 
                             
Interest Expense:
                            
Interest expense to affiliates
  6   5   17   -   4   3   2 
Interest expense to FirstEnergy
  4   -   1   1   -   -   1 

*  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.
254


Affiliated Company Transactions - 2008 FES  OE  CEI  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
Revenues:                     
Electric sales to affiliates
 $2,968  $70  $-  $30  $-  $-  $- 
Ground lease with ATSI  -   12   7   2   -   -   - 
                             
Expenses:
                            
Purchased power from affiliates
  101   1,203   766   411   -   304   284 
Support services
  552   145   67   62   90   57   56 
                             
Investment Income:
                            
Interest income from affiliates
  -   15   1   20   1   -   1 
Interest income from FirstEnergy
  13   13   -   -   -   -   - 
                             
Interest Expense:
                            
Interest expense to affiliates
  4   3   19   1   3   2   2 
Interest expense to FirstEnergy
  26   -   7   2   5   4   5 

Affiliated Company Transactions —              
2010 FES OE CEI TE JCP&L Met-Ed Penelec
  (In millions)
Revenues:              
Electric sales to affiliates $2,227
 $190
 $2
 $46
 $—
 $73
 $65
Ground lease with ATSI —
 12
 7
 2
 —
 —
 —
Other 88
 1
 7
 1
 —
 10
 —
Expenses:              
Purchased power from affiliates 371
 522
 361
 181
 —
 612
 643
Fuel 46
 —
 —
 —
 —
 —
 —
Support services 620
 128
 64
 52
 94
 59
 58
Investment Income:              
Interest income from affiliates —
 —
 —
 12
 —
 —
 —
Interest income from FE 3
 —
 —
 —
 —
 —
 —
Interest Expense:              
Interest expense to affiliates 9
 3
 14
 1
 4
 2
 2
Interest expense to FE —
 —
 1
 —
 —
 —
 —
Affiliated Company Transactions - 2007 FES  OE  CEI  TE  JCP&L  Met-Ed  Penelec 
    
Revenues:                     
Electric sales to affiliates
 $2,901  $73  $92  $167  $-  $-  $- 
Ground lease with ATSI  -   12   7   2   -   -   - 
                             
Expenses:
                            
Purchased power from affiliates
  234   1,261   770   392   -   290   285 
Support services
  560   146   70   55   100   54   58 
                             
Investment Income:
                            
Interest income from affiliates
  -   30   17   18   1   1   1 
Interest income from FirstEnergy
  28   29   2   -   -   -   - 
                             
Interest Expense:
                            
Interest expense to affiliates
  31   1   1   -   1   1   1 
Interest expense to FirstEnergy
  34   -   1   10   11   10   11 

Affiliated Company Transactions —              
2009 FES OE CEI TE JCP&L Met-Ed Penelec
  (In millions)
Revenues:              
Electric sales to affiliates $2,826
 $189
 $2
 $38
 $—
 $—
 $—
Ground lease with ATSI —
 12
 7
 2
 —
 —
 —
Other 30
 1
 6
 1
 —
 10
 —
Expenses:              
Purchased power from affiliates 222
 993
 735
 393
 —
 365
 342
Fuel 15
 —
 —
 —
 —
 —
 —
Support services 584
 141
 62
 59
 91
 54
 57
Investment Income:              
Interest income from affiliates —
 15
 —
 17
 —
 —
 —
Interest income from FE 4
 1
 —
 —
 —
 1
 —
Interest Expense:              
Interest expense to affiliates 6
 5
 17
 2
 4
 3
 2
Interest expense to FE 4
 1
 1
 1
 —
 —
 1
FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to FES and the Registrant Utilities from FESC, AESC and FENOC. The majority of costs are directly billed or assigned at no more than cost. The remaining costs are for services that are provided on behalf of more than one company, or costs that cannot be precisely identified and are allocated using formulas developed by FESC, AESC and FENOC. The current allocation or assignment formulas used and their bases include multiple factor formulas: each company'scompany’s proportionate amount of FirstEnergy'sFirstEnergy’s aggregate direct payroll, number of employees, asset balances, revenues, number of customers, other factors and specific departmental charge ratios. Management believes that these allocation methods are reasonable. Intercompany transactions with FirstEnergy and its other subsidiaries are generally settled under commercial terms within thirty days.

FES and the Utilities are parties to an intercompany income tax allocation agreement with FirstEnergy and its other subsidiaries that provides for the allocation of consolidated tax liabilities. Net tax benefits attributable to FirstEnergy are generally reallocated to the subsidiaries of FirstEnergy that have taxable income. That allocation is accounted for as a capital contribution to the company receiving the tax benefit (see Note 5, Taxes).
18. SUPPLEMENTAL GUARANTOR INFORMATION
242

19.SUPPLEMENTAL GUARANTOR INFORMATION

As discussed in Note 7,6, Leases FES has fully and unconditionally guaranteed all of FGCO'sFGCO’s obligations under each of the leases associated with Bruce Mansfield Unit 1. The consolidating statementsConsolidating Statements of incomeIncome for the three years ended December 31, 2009, consolidating balance sheets2011, Consolidating Balance Sheets as of December 31, 2009,2011, and December 31, 2008,2010, and condensed consolidating statementsCondensed Consolidating Statements of cash flowsCash Flows for the three years ended December 31, 2009,2011, for FES (parent and guarantor), FGCO and NGC (non-guarantor) are presented below.below and have been revised, as applicable, for the change in accounting for pensions and OPEB (see Note 1, Organization, Basis of Presentation and Significant Accounting Policies). Investments in wholly owned subsidiaries are accounted for by FES using the equity method. Results of operations for FGCO and NGC are, therefore, reflected in FES’ investment accounts and earnings as if operating lease treatment was achieved (see Note 7)6, Leases). The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and the entries required to reflect operating lease treatment


255


associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction.
FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATING STATEMENTS OF INCOME
For the Year Ended December 31, 2011 FES FGCO NGC Eliminations Consolidated
  (In millions)
REVENUES $5,387
 $2,666
 $1,647
 $(4,223) $5,477
           
OPERATING EXPENSES:          
Fuel 12
 1,138
 194
 —
 1,344
Purchased power from affiliates 4,208
 5
 252
 (4,223) 242
Purchased power from non-affiliates 1,378
 —
 —
 —
 1,378
Other operating expenses 574
 427
 578
 51
 1,630
Pensions and OPEB mark-to-market adjustment 10
 68
 93
 —
 171
Provision for depreciation 4
 127
 150
 (6) 275
General taxes 64
 37
 23
 —
 124
Impairment of long-lived assets —
 294
 —
 —
 294
Total operating expenses 6,250
 2,096
 1,290
 (4,178) 5,458
           
OPERATING INCOME (LOSS) (863) 570
 357
 (45) 19
           
OTHER INCOME (EXPENSE):          
Investment income 1
 —
 56
 —
 57
Miscellaneous income, including net income from equity investees 924
 24
 —
 (918) 30
Interest expense — affiliates (2) (3) (2) (1) (8)
Interest expense — other (94) (109) (64) 64
 (203)
Capitalized interest —
 12
 23
 —
 35
Total other income (expense) 829
 (76) 13
 (855) (89)
           
INCOME (LOSS) BEFORE INCOME TAXES (34) 494
 370
 (900) (70)
           
INCOME TAXES (BENEFITS) 25
 (112) 58
 18
 (11)
           
NET INCOME (LOSS) $(59) $606
 $312
 $(918) $(59)


256
243


FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME
CONDENSED CONSOLIDATING STATEMENTS OF INCOME 
                
                
                
For the Year Ended December 31, 2009 FES  FGCO  NGC  Eliminations  Consolidated 
  (In thousands) 
                
REVENUES $4,390,111  $2,216,237  $1,360,522  $(3,238,533) $4,728,337 
                     
EXPENSES:                    
Fuel  18,416   971,021   138,026   -   1,127,463 
Purchased power from affiliates  3,220,197   18,336   222,406   (3,238,533)  222,406 
Purchased power from non-affiliates  996,383   -   -   -   996,383 
Other operating expenses  220,660   395,330   518,473   48,762   1,183,225 
Provision for depreciation  4,147   121,007   139,488   (5,249)  259,393 
General taxes  18,214   44,075   24,626   -   86,915 
Total expenses  4,478,017   1,549,769   1,043,019   (3,195,020)  3,875,785 
                     
OPERATING INCOME  (87,906)  666,468   317,503   (43,513)  852,552 
                     
OTHER INCOME (EXPENSE):                    
Investment income  5,297   683   119,246   -   125,226 
Miscellaneous income (expense), including                    
net income from equity investees  656,451   (3,931)  61   (645,911)  6,670 
Interest expense to affiliates  (135)  (5,619)  (4,352)  -   (10,106)
Interest expense - other  (44,837)  (99,802)  (62,034)  64,553   (142,120)
Capitalized interest  212   49,577   10,363   -   60,152 
Total other income (expense)  616,988   (59,092)  63,284   (581,358)  39,822 
                     
INCOME BEFORE INCOME TAXES  529,082   607,376   380,787   (624,871)  892,374 
                     
INCOME TAXES  (48,002)  207,171   135,785   20,336   315,290 
                     
NET INCOME $577,084  $400,205  $245,002  $(645,207) $577,084 
For the Year Ended December 31, 2010 FES FGCO NGC Eliminations Consolidated
  (In millions)
REVENUES $5,665
 $2,435
 $1,568
 $(3,840) $5,828
           
OPERATING EXPENSES:          
Fuel 31
 1,200
 172
 —
 1,403
Purchased power from affiliates 3,948
 30
 232
 (3,839) 371
Purchased power from non-affiliates 1,585
 —
 —
 —
 1,585
Other operating expenses 314
 357
 511
 48
 1,230
Pensions and OPEB mark-to-market adjustment 11
 37
 59
 —
 107
Provision for depreciation 3
 100
 148
 (5) 246
General taxes 24
 42
 28
 —
 94
Impairment of long-lived assets —
 388
 —
 —
 388
Total operating expenses 5,916
 2,154
 1,150
 (3,796) 5,424
           
OPERATING INCOME (LOSS) (251) 281
 418
 (44) 404
           
OTHER INCOME (EXPENSE):          
Investment income 5
 1
 53
 —
 59
Miscellaneous income (expense), including net income from equity investees 453
 1
 —
 (437) 17
Interest expense — affiliates —
 (8) (2) —
 (10)
Interest expense — other (96) (109) (65) 64
 (206)
Capitalized interest —
 76
 16
 —
 92
Total other income (expense) 362
 (39) 2
 (373) (48)
           
INCOME (LOSS) BEFORE INCOME TAXES 111
 242
 420
 (417) 356
           
INCOME TAXES (BENEFITS) (120) 74
 153
 18
 125
           
NET INCOME (LOSS) $231
 $168
 $267
 $(435) $231


257
244

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME 
                
                
                
For the Year Ended December 31, 2008 FES  FGCO  NGC  Eliminations  Consolidated 
  (In thousands) 
                
REVENUES $4,470,112  $2,275,451  $1,204,534  $(3,431,744) $4,518,353 
                     
EXPENSES:                    
Fuel  16,322   1,171,993   126,978   -   1,315,293 
Purchased power from non-affiliates  778,882   -   -   -   778,882 
Purchased power from affiliates  3,417,126   14,618   101,409   (3,431,744)  101,409 
Other operating expenses  116,972   416,723   502,096   48,757   1,084,548 
Provision for depreciation  5,986   119,763   111,529   (5,379)  231,899 
General taxes  19,260   46,153   22,591   -   88,004 
Total expenses  4,354,548   1,769,250   864,603   (3,388,366)  3,600,035 
                     
OPERATING INCOME  115,564   506,201   339,931   (43,378)  918,318 
                     
OTHER INCOME (EXPENSE):                    
Investment income (loss)  10,953   2,034   (35,665)  -   (22,678)
Miscellaneous income (expense), including                    
net income from equity investees  438,214   (5,400)  -   (431,116)  1,698 
Interest expense to affiliates  (314)  (20,342)  (9,173)  -   (29,829)
Interest expense - other  (24,674)  (95,926)  (56,486)  65,404   (111,682)
Capitalized interest  142   39,934   3,688   -   43,764 
Total other income (expense)  424,321   (79,700)  (97,636)  (365,712)  (118,727)
                     
INCOME BEFORE INCOME TAXES  539,885   426,501   242,295   (409,090)  799,591 
                     
INCOME TAXES  33,475   155,100   90,247   14,359   293,181 
                     
NET INCOME $506,410  $271,401  $152,048  $(423,449) $506,410 

245

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME
CONDENSED CONSOLIDATING STATEMENTS OF INCOME 
                
                
                
For the Year Ended December 31, 2007 FES  FGCO  NGC  Eliminations  Consolidated 
  (In thousands) 
                
REVENUES $4,345,790  $1,982,166  $1,062,026  $(3,064,955) $4,325,027 
                     
EXPENSES:                    
Fuel  26,169   942,946   117,895   -   1,087,010 
Purchased power from non-affiliates  764,090   -   -   -   764,090 
Purchased power from affiliates  3,038,786   186,415   73,844   (3,064,955)  234,090 
Other operating expenses  161,797   352,856   514,389   11,997   1,041,039 
Provision for depreciation  2,269   99,741   92,239   (1,337)  192,912 
General taxes  20,953   41,456   24,689   -   87,098 
Total expenses  4,014,064   1,623,414   823,056   (3,054,295)  3,406,239 
                     
OPERATING INCOME  331,726   358,752   238,970   (10,660)  918,788 
                     
OTHER INCOME (EXPENSE):                    
Investment income  22,845   2,799   15,793   -   41,437 
Miscellaneous income (expense), including                    
net income from equity investees  319,133   1,411   (913)  (308,192)  11,439 
Interest expense to affiliates  (1,320)  (48,536)  (15,645)  -   (65,501)
Interest expense - other  (9,503)  (59,412)  (39,458)  16,174   (92,199)
Capitalized interest  35   14,369   5,104   -   19,508 
Total other income (expense)  331,190   (89,369)  (35,119)  (292,018)  (85,316)
                     
INCOME BEFORE INCOME TAXES  662,916   269,383   203,851   (302,678)  833,472 
                     
INCOME TAXES  134,052   90,801   77,467   2,288   304,608 
                     
NET INCOME $528,864  $178,582  $126,384  $(304,966) $528,864 
For the Year Ended December 31, 2009 FES FGCO NGC Eliminations Consolidated
  (In millions)
REVENUES $4,390
 $2,216
 $1,361
 $(3,239) $4,728
           
OPERATING EXPENSES:          
Fuel 18
 973
 138
 —
 1,129
Purchased power from affiliates 3,221
 18
 222
 (3,239) 222
Purchased power from non-affiliates 996
 —
 —
 —
 996
Other operating expenses 220
 377
 497
 49
 1,143
Pensions and OPEB mark-to-market adjustment 13
 56
 81
 —
 150
Provision for depreciation 4
 122
 142
 (6) 262
General taxes 18
 45
 24
 —
 87
Impairment of long-lived assets —
 6
 —
 —
 6
Total operating expenses 4,490
 1,597
 1,104
 (3,196) 3,995
           
OPERATING INCOME (LOSS) (100) 619
 257
 (43) 733
           
OTHER INCOME (EXPENSE):          
Investment income 5
 —
 120
 —
 125
Miscellaneous income (expense), including net income from equity investees 585
 2
 —
 (574) 13
Interest expense to affiliates —
 (6) (4) —
 (10)
Interest expense — other (44) (99) (62) 63
 (142)
Capitalized interest —
 50
 10
 —
 60
Total other income (expense) 546
 (53) 64
 (511) 46
           
INCOME (LOSS) BEFORE INCOME TAXES 446
 566
 321
 (554) 779
           
INCOME TAXES (BENEFITS) (52) 196
 117
 20
 281
           
NET INCOME (LOSS) $498
 $370
 $204
 $(574) $498



258
246


FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING BALANCE SHEETS
CONDENSED CONSOLIDATING BALANCE SHEETS 
                
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 
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  99,411   71,179   18,755   (51,114)  138,231 
   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 
As of December 31, 2011 FES FGCO NGC Eliminations Consolidated
  (In millions)
ASSETS          
CURRENT ASSETS:          
Cash and cash equivalents $—
 $7
 $—
 $—
 $7
Receivables-          
Customers 424
 —
 —
 —
 424
Associated companies 476
 643
 262
 (781) 600
Other 28
 20
 13
 —
 61
Notes receivable from associated companies 155
 1,346
 69
 (1,187) 383
Materials and supplies, at average cost 60
 232
 200
 —
 492
Derivatives 219
 —
 —
 —
 219
Prepayments and other 11
 26
 1
 —
 38
  1,373
 2,274
 545
 (1,968) 2,224
PROPERTY, PLANT AND EQUIPMENT:          
In service 84
 5,573
 5,711
 (385) 10,983
Less — Accumulated provision for depreciation 28
 1,813
 2,449
 (180) 4,110
  56
 3,760
 3,262
 (205) 6,873
Construction work in progress 29
 195
 790
 —
 1,014
  85
 3,955
 4,052
 (205) 7,887
INVESTMENTS:          
Nuclear plant decommissioning trusts —
 —
 1,223
 —
 1,223
Investment in associated companies 5,716
 —
 —
 (5,716) —
Other —
 7
 —
 —
 7
  5,716
 7
 1,223
 (5,716) 1,230
DEFERRED CHARGES AND OTHER ASSETS:          
Accumulated deferred income tax benefits 10
 307
 —
 (317) —
Customer intangibles 123
 —
 —
 —
 123
Goodwill 24
 —
 —
 —
 24
Property taxes —
 20
 23
 —
 43
Unamortized sale and leaseback costs —
 5
 —
 75
 80
Derivatives 118
 —
 —
 —
 118
Other 50
 99
 3
 (62) 90
  325
 431
 26
 (304) 478
  $7,499
 $6,667
 $5,846
 $(8,193) $11,819
LIABILITIES AND CAPITALIZATION          
CURRENT LIABILITIES:          
Currently payable long-term debt $1
 $411
 $513
 $(20) $905
Short-term borrowings-          
Associated companies 1,065
 89
 32
 (1,186) —
Accounts payable-          
Associated companies 777
 228
 211
 (780) 436
Other 99
 121
 —
 —
 220
Accrued taxes 84
 42
 110
 (9) 227
Derivatives 189
 —
 —
 —
 189
Other 62
 141
 16
 42
 261
  2,277
 1,032
 882
 (1,953) 2,238
CAPITALIZATION:          
Total equity 3,593
 3,097
 2,587
 (5,700) 3,577
Long-term debt and other long-term obligations 1,483
 1,905
 641
 (1,230) 2,799
  5,076
 5,002
 3,228
 (6,930) 6,376
NONCURRENT LIABILITIES:          
Deferred gain on sale and leaseback transaction —
 —
 —
 925
 925
Accumulated deferred income taxes 12
 —
 510
 (236) 286
Asset retirement obligations —
 28
 876
 —
 904
Retirement benefits 56
 300
 —
 —
 356
Lease market valuation liability —
 171
 —
 —
 171
Other 78
 134
 350
 1
 563
  146
 633
 1,736
 690
 3,205
  $7,499
 $6,667
 $5,846
 $(8,193) $11,819


259
247


FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEET
CONDENSED CONSOLIDATING BALANCE SHEETS 
               
As of December 31, 2008 FES  FGCO  NGC  Eliminations  Consolidated 
As of December 31, 2010 FES FGCO NGC Eliminations Consolidated
 (In thousands)  (In millions)
ASSETS                         
CURRENT ASSETS:                         
Cash and cash equivalents $-  $39  $-  $-  $39  $—
 $9
 $—
 $—
 $9
Receivables-                              
Customers  86,123   -   -   -   86,123  366
 —
 —
 —
 366
Associated companies  363,226   225,622   113,067   (323,815)  378,100  333
 357
 126
 (338) 478
Other  991   11,379   12,256   -   24,626  21
 56
 13
 —
 90
Notes receivable from associated companies  107,229   21,946   -   -   129,175  34
 189
 174
 —
 397
Materials and supplies, at average cost  5,750   303,474   212,537   -   521,761  41
 276
 228
 —
 545
Derivatives 181
 —
 —
 —
 181
Prepayments and other  76,773   35,102   660   -   112,535  48
 11
 1
 —
 60
  640,092   597,562   338,520   (323,815)  1,252,359 
                     1,024
 898
 542
 (338) 2,126
PROPERTY, PLANT AND EQUIPMENT:                              
In service  134,905   5,420,789   4,705,735   (389,525)  9,871,904  99
 6,214
 5,499
 (385) 11,427
Less - Accumulated provision for depreciation  13,090   2,702,110   1,709,286   (169,765)  4,254,721 
Less — Accumulated provision for depreciation 18
 2,022
 2,173
 (175) 4,038
  121,815   2,718,679   2,996,449   (219,760)  5,617,183  81
 4,192
 3,326
 (210) 7,389
Construction work in progress  4,470   1,441,403   301,562   -   1,747,435  9
 520
 534
 —
 1,063
  126,285   4,160,082   3,298,011   (219,760)  7,364,618  90
 4,712
 3,860
 (210) 8,452
                    
INVESTMENTS:                              
Nuclear plant decommissioning trusts  -   -   1,033,717   -   1,033,717  —
 —
 1,146
 —
 1,146
Long-term notes receivable from associated companies  -   -   62,900   -   62,900 
Investment in associated companies  3,596,152   -   -   (3,596,152)  -  4,773
 —
 —
 (4,773) —
Other  1,913   59,476   202   -   61,591  —
 12
 —
 —
 12
  3,598,065   59,476   1,096,819   (3,596,152)  1,158,208  4,773
 12
 1,146
 (4,773) 1,158
                    
DEFERRED CHARGES AND OTHER ASSETS:                              
Accumulated deferred income taxes  24,703   476,611   -   (233,552)  267,762  42
 407
 —
 (449) —
Lease assignment receivable from associated companies  -   71,356   -   -   71,356 
Customer intangibles 134
 —
 —
 —
 134
Goodwill  24,248   -   -   -   24,248  24
 —
 —
 —
 24
Property taxes  -   27,494   22,610   -   50,104  —
 16
 25
 —
 41
Unamortized sale and leaseback costs  -   20,286   -   49,646   69,932  —
 10
 —
 63
 73
Derivatives 98
 —
 —
 —
 98
Other  59,642   59,674   21,743   (44,625)  96,434  22
 70
 14
 (57) 49
  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  320
 503
 39
 (443) 419
                     $6,207
 $6,125
 $5,587
 $(5,764) $12,155
LIABILITIES AND CAPITALIZATION                              
CURRENT LIABILITIES:                              
Currently payable long-term debt $5,377  $925,234  $1,111,183  $(16,896) $2,024,898  $101
 $419
 $632
 $(20) $1,132
Short-term borrowings-                              
Associated companies  1,119   257,357   6,347   -   264,823  —
 12
 —
 —
 12
Other  1,000,000   -   -   -   1,000,000 
Accounts payable-                              
Associated companies  314,887   221,266   250,318   (314,133)  472,338  351
 213
 250
 (348) 466
Other  35,367   119,226   -   -   154,593  139
 102
 —
 —
 241
Accrued taxes  8,272   60,385   30,790   (19,681)  79,766  3
 36
 31
 —
 70
Derivatives 266
 —
 —
 —
 266
Other  61,034   136,867   13,685   36,853   248,439  52
 148
 15
 37
 252
  1,426,056   1,720,335   1,412,323   (313,857)  4,244,857  912
 930
 928
 (331) 2,439
                    
CAPITALIZATION:                              
Common stockholder's equity  2,944,423   1,832,678   1,752,580   (3,585,258)  2,944,423 
Common stockholder’s equity 3,619
 2,495
 2,265
 (4,760) 3,619
Long-term debt and other long-term obligations  61,508   1,328,921   469,839   (1,288,820)  571,448  1,519
 2,119
 793
 (1,250) 3,181
  3,005,931   3,161,599   2,222,419   (4,874,078)  3,515,871 
                     5,138
 4,614
 3,058
 (6,010) 6,800
NONCURRENT LIABILITIES:                              
Deferred gain on sale and leaseback transaction  -   -   -   1,026,584   1,026,584  —
 —
 —
 959
 959
Accumulated deferred income taxes  -   -   206,907   (206,907)  -  —
 —
 449
 (382) 67
Accumulated deferred investment tax credits  -   39,439   23,289   -   62,728 
Asset retirement obligations  -   24,134   838,951   -   863,085  —
 27
 865
 —
 892
Retirement benefits  22,558   171,619   -   -   194,177  48
 237
 —
 —
 285
Property taxes  -   27,494   22,610   -   50,104 
Lease market valuation liability  -   307,705   -   -   307,705  —
 217
 —
 —
 217
Other  18,490   20,216   51,204   -   89,910  109
 100
 287
 —
 496
  41,048   590,607   1,142,961   819,677   2,594,293  157
 581
 1,601
 577
 2,916
 $4,473,035  $5,472,541  $4,777,703  $(4,368,258) $10,355,021  $6,207
 $6,125
 $5,587
 $(5,764) $12,155



260
248


FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS 
        
      
                
For the Year Ended December 31, 2009 FES  FGCO  NGC  Eliminations  Consolidated 
  (In thousands) 
                
NET CASH PROVIDED FROM (USED FOR)               
OPERATING ACTIVITIES $(20,027) $790,411  $621,649  $(17,744) $1,374,289 
                     
CASH FLOWS FROM FINANCING ACTIVITIES:                    
New financing-                    
Long-term debt  1,498,087   576,800   363,515   -   2,438,402 
Equity contributions from parent  -   100,000   150,000   (250,000)  - 
Redemptions and repayments-                    
Long-term debt  (1,766)  (320,754)  (404,383)  17,747   (709,156)
Short-term borrowings, net  (901,119)  (248,120)  (6,347)  -   (1,155,586)
Other  (12,054)  (6,157)  (3,576)  (3)  (21,790)
Net cash provided from financing activities  583,148   101,769   99,209   (232,256)  551,870 
                     
CASH FLOWS FROM INVESTING ACTIVITIES:                    
Property additions  (4,372)  (671,691)  (546,869)  -   (1,222,932)
Proceeds from asset sales  -   18,371   -   -   18,371 
Sales of investment securities held in trusts  -   -   1,379,154   -   1,379,154 
Purchases of investment securities held in trusts  -   -   (1,405,996)  -   (1,405,996)
Loans to associated companies, net  (309,175)  (218,890)  (147,863)  -   (675,928)
Investment in subsidiaries  (250,000)  -   -   250,000   - 
Other  426   (20,006)  725   -   (18,855)
Net cash used for investing activities  (563,121)  (892,216)  (720,849)  250,000   (1,926,186)
                     
Net change in cash and cash equivalents  -   (36)  9   -   (27)
Cash and cash equivalents at beginning of year  -   39   -   -   39 
Cash and cash equivalents at end of year $-  $3  $9  $-  $12 
For the Year Ended December 31, 2011 FES FGCO NGC Eliminations Consolidated
  (In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $(790) $926
 $702
 $(19) $819
           
CASH FLOWS FROM FINANCING ACTIVITIES:          
New Financing-          
Long-term debt —
 140
 107
 —
 247
Short-term borrowings, net 1,065
 78
 32
 (1,186) (11)
Redemptions and Repayments-          
Long-term debt (136) (362) (377) 19
 (856)
Short-term borrowings, net —
 —
 —
 —
 —
Other (9) (1) (1) —
 (11)
Net cash used for financing activities 920
 (145) (239) (1,167) (631)
           
CASH FLOWS FROM INVESTING ACTIVITIES:          
Property additions (24) (205) (520) —
 (749)
Proceeds from asset sales 9
 590
 —
 —
 599
Sales of investment securities held in trusts —
 —
 1,843
 —
 1,843
Purchases of investment securities held in trusts —
 —
 (1,890) —
 (1,890)
Loans to associated companies, net (120) (1,157) 105
 1,186
 14
Customer acquisition costs (3) —
 —
 —
 (3)
Other 8
 (11) (1) —
 (4)
Net cash used for investing activities (130) (783) (463) 1,186
 (190)
Net change in cash and cash equivalents —
 (2) —
 —
 (2)
Cash and cash equivalents at beginning of period —
 9
 —
 —
 9
Cash and cash equivalents at end of period $—
 $7
 $—
 $—
 $7


261
249


FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS 
        
      
                
For the Year Ended December 31, 2008 FES  FGCO  NGC  Eliminations  Consolidated 
  (In thousands) 
                
NET CASH PROVIDED FROM OPERATING ACTIVITIES $40,791  $350,986  $478,047  $(16,896) $852,928 
                     
CASH FLOWS FROM FINANCING ACTIVITIES:                    
New financing-                    
Long-term debt  -   353,325   265,050   -   618,375 
Equity contributions from parent  280,000   675,000   175,000   (850,000)  280,000 
Short-term borrowings, net  701,119   18,571   -   (18,931)  700,759 
Redemptions and repayments-                    
Long-term debt  (2,955)  (293,349)  (183,132)  16,896   (462,540)
Short-term borrowings, net  -   -   (18,931)  18,931   - 
Common stock dividend payment  (43,000)  -   -   -   (43,000)
Other  -   (3,107)  (2,040)  -   (5,147)
Net cash provided from financing activities  935,164   750,440   235,947   (833,104)  1,088,447 
                     
CASH FLOWS FROM INVESTING ACTIVITIES:                    
Property additions  (43,244)  (1,047,917)  (744,468)  -   (1,835,629)
Proceeds from asset sales  -   23,077   -   -   23,077 
Sales of investment securities held in trusts  -   -   950,688   -   950,688 
Purchases of investment securities held in trusts  -   -   (987,304)  -   (987,304)
Loans repayments from (loans to) associated companies  (83,457)  (21,946)  69,012   -   (36,391)
Investment in subsidiary  (850,000)  -   -   850,000   - 
Other  744   (54,601)  (1,922)  -   (55,779)
Net cash used for investing activities  (975,957)  (1,101,387)  (713,994)  850,000   (1,941,338)
                     
Net change in cash and cash equivalents  (2)  39   -   -   37 
Cash and cash equivalents at beginning of year  2   -   -   -   2 
Cash and cash equivalents at end of year $-  $39  $-  $-  $39 
For the Year Ended December 31, 2010 FES FGCO NGC Eliminations Consolidated
  (In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $(260) $380
 $685
 $(19) $786
           
CASH FLOWS FROM FINANCING ACTIVITIES:          
New Financing-          
Long-term debt —
 318
 397
 —
 715
Short-term borrowings, net —
 2
 —
 —
 2
Redemptions and Repayments-          
Long-term debt (1) (341) (449) 19
 (772)
Other —
 (1) (1) —
 (2)
Net cash used for financing activities (1) (22) (53) 19
 (57)
           
CASH FLOWS FROM INVESTING ACTIVITIES:          
Property additions (9) (518) (508) —
 (1,035)
Proceeds from asset sales —
 117
 —
 —
 117
Sales of investment securities held in trusts —
 —
 1,927
 —
 1,927
Purchases of investment securities held in trusts —
 —
 (1,974) —
 (1,974)
Loans to associated companies, net 382
 52
 (26) —
 408
Customer acquisition costs (113) —
 —
 —
 (113)
Leasehold improvement payments to associated companies —
 —
 (51) —
 (51)
Other 1
 —
 —
 —
 1
Net cash provided from (used for) investing activities 261
 (349) (632) —
 (720)
Net change in cash and cash equivalents —
 9
 —
 —
 9
Cash and cash equivalents at beginning of period —
 —
 —
 —
 —
Cash and cash equivalents at end of period $—
 $9
 $—
 $—
 $9


262
250


FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS 
        
      
                
For the Year Ended December 31, 2007 FES  FGCO  NGC  Eliminations  Consolidated 
  (In thousands) 
                
NET CASH PROVIDED FROM (USED FOR)               
OPERATING ACTIVITIES $(18,017) $55,172  $263,468  $(6,306) $294,317 
                     
CASH FLOWS FROM FINANCING ACTIVITIES:                    
New financing-                    
Long-term debt  -   1,576,629   179,500   (1,328,919)  427,210 
Equity contributions from parent  700,000   700,000   -   (700,000)  700,000 
Short-term borrowings, net  300,000   -   25,278   (325,278)  - 
Redemptions and repayments-                    
Common stock  (600,000)  -   -   -   (600,000)
Long-term debt  -   (1,048,647)  (494,070)  6,306   (1,536,411)
Short-term borrowings, net  -   (783,599)  -   325,278   (458,321)
Common stock dividend payment  (117,000)  -   -   -   (117,000)
Other  -   (3,474)  (1,725)  -   (5,199)
Net cash provided from (used for) financing activities  283,000   440,909   (291,017)  (2,022,613)  (1,589,721)
                     
CASH FLOWS FROM INVESTING ACTIVITIES:                    
Property additions  (10,603)  (502,311)  (225,795)  -   (738,709)
Proceeds from asset sales  -   12,990   -   -   12,990 
Proceeds from sale and leaseback transaction  -   -   -   1,328,919   1,328,919 
Sales of investment securities held in trusts  -   -   655,541   -   655,541 
Purchases of investment securities held in trusts  -   -   (697,763)  -   (697,763)
Loans repayments from associated companies  441,966   -   292,896   -   734,862 
Investment in subsidiary  (700,000)  -   -   700,000   - 
Other  3,654   (6,760)  2,670   -   (436)
Net cash provided from (used for) investing activities  (264,983)  (496,081)  27,549   2,028,919   1,295,404 
                     
Net change in cash and cash equivalents  -   -   -   -   - 
Cash and cash equivalents at beginning of year  2   -   -   -   2 
Cash and cash equivalents at end of year $2  $-  $-  $-  $2 
For the Year Ended December 31, 2009 FES FGCO NGC Eliminations Consolidated
  (In millions)
NET CASH PROVIDED FROM (USED FOR)OPERATING ACTIVITIES $(20) $790
 $622
 $(18) $1,374
           
CASH FLOWS FROM FINANCING ACTIVITIES:          
New Financing-          
Long-term debt 1,498
 577
 363
 —
 2,438
Equity contributions from parent —
 100
 150
 (250) —
Redemptions and Repayments-          
Long-term debt (2) (321) (404) 18
 (709)
Short-term borrowings, net (901) (248) (7) —
 (1,156)
Other (12) (6) (3) —
 (21)
Net cash provided from financing activities 583
 102
 99
 (232) 552
           
CASH FLOWS FROM INVESTING ACTIVITIES:          
Property additions (4) (672) (547) —
 (1,223)
Proceeds from asset sales —
 18
 —
 —
 18
Sales of investment securities held in trusts —
 —
 1,379
 —
 1,379
Purchases of investment securities held in trusts —
 —
 (1,406) —
 (1,406)
Loans to associated companies, net (309) (219) (148) —
 (676)
Investment in subsidiary (250) —
 —
 250
 —
Other —
 (19) 1
 —
 (18)
Net cash used for investing activities (563) (892) (721) 250
 (1,926)
Net change in cash and cash equivalents —
 —
 —
 —
 —
Cash and cash equivalents at beginning of period —
 —
 —
 —
 —
Cash and cash equivalents at end of period $—
 $—
 $—
 $—
 $—



263
251


20.SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED)
19. SEGMENT INFORMATION
With the completion of the AE merger in the first quarter of 2011, FirstEnergy reorganized its management structure, which resulted in changes to its operating segments to be consistent with the manner in which management views the business. The new structure supports the combined company's primary operations - distribution, transmission, generation and the marketing and sale of its products. The external segment reporting is consistent with the internal financial reporting used by FirstEnergy's chief executive officer (its chief operating decision maker) to regularly assess the performance of the business and allocate resources. FirstEnergy now has three reportable operating segments - Regulated Distribution, Regulated Independent Transmission and Competitive Energy Services.
Prior to the change in composition of business segments, FirstEnergy's business was comprised of two reportable operating segments. The Energy Delivery Services segment was comprised of FirstEnergy's then eight existing utility operating companies that transmit and distribute electricity to customers and purchase power to serve their POLR and default service requirements. The Competitive Energy Services segment was comprised of FES, which supplies electric power to end-use customers through retail and wholesale arrangements. The “Other/Corporate” amounts consisted of corporate items and other businesses that were below the quantifiable threshold for separate disclosure. Disclosures for FirstEnergy's operating segments for 2010 have been reclassified to conform to the current presentation.
The changes in FirstEnergy's reportable segments during 2011 consisted primarily of the following:
Energy Delivery Services was renamed Regulated Distribution and the operations of MP, PE and WP, which were acquired as part of the merger with AE, and certain regulatory asset recovery mechanisms formerly included in the “Other” segment, were placed into this segment.
A new Regulated Independent Transmission segment was created consisting of ATSI, and the operations of TrAIL and FirstEnergy's interest in PATH; TrAIL and PATH were acquired as part of the merger with AE. The transmission assets and operations of JCP&L, Met-Ed, Penelec, MP, PE and WP remained within the Regulated Distribution segment.
AE Supply, an operator of generation facilities that was acquired as part of the merger with AE, was placed into the Competitive Energy Services segment.

The Regulated Distribution segment distributes electricity through FirstEnergy's ten utility distribution companies, serving approximately 6 million customers within 67,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also includes the transmission operations of JCP&L, Met-Ed, Penelec, WP, MP and PE and the regulated electric generation facilities in West Virginia and New Jersey which MP and JCP&L, respectively, own or contractually control.
The Regulated Distribution segment's revenues are primarily derived from the delivery of electricity within FirstEnergy's service areas, cost recovery of regulatory assets and the sale of electric generation service to retail customers who have not selected an alternative supplier (POLR, SOS or default service) in its Maryland, New Jersey, Ohio and Pennsylvania franchise areas. Its results reflect the commodity costs of securing electric generation from FES and AE Supply and from non-affiliated power suppliers and the deferral and amortization of certain fuel costs.
The Regulated Independent Transmission segment transmits electricity through transmission lines and its revenues are primarily derived from a formulaic rate that recovers costs and a return on investment for capital expenditures in connection with TrAIL, PATH and other projects, revenues from providing transmission services to electric energy providers and power marketers, and revenues from operating a portion of the FirstEnergy transmission system. Its results reflect the net transmission expenses related to the delivery of the respective generation loads.
The Competitive Energy Services segment supplies, through FES and AE Supply, electric power to end-use customers through retail and wholesale arrangements, including competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland and the provision of partial POLR and default service for some utilities in Ohio and Pennsylvania. FES purchases the entire output of the 18 generating facilities which it owns and operates through its FGCO subsidiary (fossil and hydroelectric generating facilities) and owns, through its NGC subsidiary, FirstEnergy's nuclear generating facilities. FENOC, a separate subsidiary of FirstEnergy, operates and maintains NGC's nuclear generating facilities as well as the output relating to leasehold interests of OE and TE in certain of those facilities that are subject to sale and leaseback arrangements with non-affiliates, pursuant to full output, cost-of-service PSAs. AE Supply together with its consolidated subsidiary, AGC owns, operates and controls the electric generation capacity of 18 facilities. AGC owns and sells generation capacity to AE Supply and MP, which own approximately 59% and 41% of AGC, respectively. AGC's sole asset is a 40% undivided interest in the Bath County, Virginia pumped-storage hydroelectric generation facility and its connecting transmission facilities. All of AGC's revenues are derived from sales of its 1,109 MW share of generation capacity from the Bath County generation facility to AE Supply and MP.
This Competitive Energy Services segment controls approximately 17,000 MWs of capacity, excluding approximately 2,700 MWs from unregulated plants expected to be closed by September 1, 2012 (see Note 11, Impairment of Long-Lived Assets), and also purchases electricity to meet sales obligations. The segment's net income is primarily derived from electric generation sales less


264


the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO (prior to June 1, 2011) to deliver energy to the segment's customers.
Other/Corporate contains corporate items and other businesses that are below the quantifiable threshold for separate disclosure as a reportable segment.
Financial information for each of FirstEnergy's reportable segments is presented in the table below, which includes financial results for Allegheny beginning February 25, 2011. FES and the Utility Registrants do not have separate reportable operating segments.
As described in Note 1, Organization, Basis of Presentation and Significant Accounting Policies, FirstEnergy elected to change its method of recognizing actuarial gains and losses for its defined benefit pension and OPEB plans, and applied this change retrospectively to all periods presented.
Segment Financial Information
For the Years Ended December 31, Regulated Distribution Competitive Energy Services Regulated Independent Transmission Other Reconciling Adjustments Consolidated
    (In millions)
2011            
External revenues $10,004
 $5,936
 $391
 $(114) $(26) $16,191
Internal revenues —
 1,237
 —
 —
 (1,170) 67
Total Revenues 10,004
 7,173
 391
 (114) (1,196) 16,258
Depreciation and amortization 943
 415
 66
 26
 —
 1,450
Investment income 110
 56
 —
 1
 (53) 114
Net interest charges (573) (298) (46) (91) —
 (1,008)
Income taxes 335
 222
 66
 (87) 38
 574
Net income 570
 377
 112
 (149) (41) 869
Total assets 27,477
 16,796
 2,436
 617
 —
 47,326
Total goodwill 5,551
 890
 —
 —
 —
 6,441
Property additions 1,066
 927
 192
 93
 —
 2,278
             
2010            
External revenues $9,571
 $3,575
 $242
 $(88) $(35) $13,265
Internal revenues 139
 2,301
 —
 —
 (2,366) 74
Total Revenues 9,710
 5,876
 242
 (88) (2,401) 13,339
Depreciation and amortization 1,145
 284
 47
 14
 —
 1,490
Investment income 102
 51
 —
 (2) (34) 117
Net interest charges (500) (232) (22) (104) 13
 (845)
Income taxes 338
 128
 32
 (44) 8
 462
Net income 553
 210
 54
 (79) (20) 718
Total assets 22,160
 11,320
 1,064
 987
 —
 35,531
Total goodwill 5,551
 24
 —
 —
 —
 5,575
Property additions 681
 1,159
 64
 59
 —
 1,963
             
2009            
External revenues $10,916
 $1,928
 $223
 $(82) $(29) $12,956
Internal revenues —
 2,843
 —
 —
 (2,826) 17
Total Revenues 10,916
 4,771
 223
 (82) (2,855) 12,973
Depreciation and amortization 1,432
 279
 50
 15
 —
 1,776
Investment income 141
 121
 —
 4
 (62) 204
Net interest charges (478) (174) (19) (345) 38
 (978)
Income taxes 243
 305
 26
 (140) (250) 184
Net income 335
 446
 39
 (209) 245
 856
Total assets 22,663
 10,668
 974
 749
 —
 35,054
Total goodwill 5,551
 24
 —
 —
 —
 5,575
Property additions 718
 1,412
 32
 41
 —
 2,203
Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial


265


reporting primarily consist of interest expense related to holding company debt, corporate support services revenues and expenses and elimination of intersegment transactions.
Electricity sales during the years ended 2011, 2010 and 2009, were $15,117 million, $12,523 million and $12,032 million, respectively.


266


20. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED)

The following summarizes certain consolidated operating results by quarter for 20092011 and 2008.2010. All periods presented have been revised for the change in accounting for Pensions and OPEB as described further in Note 1, Organization, Basis of Presentation and Significant Accounting Policies.
FirstEnergy               
CONSOLIDATED STATEMENTS OF INCOME        
(In millions, except per share amounts)2010 2011  
As ReportedMar. 31 June 30 Sept. 30 Dec. 31 Mar. 31 June 30 Sept. 30  
Revenues$3,299
 $3,139
 $3,728
 $3,173
 $3,576
 $4,060
 $4,719
  
Other operating expense701
 673
 738
 738
 1,008
 1,098
 1,024
  
Pensions and OPEB mark-to-market adjustment—
 —
 —
 —
 —
 —
 —
  
Provision for depreciation193
 190
 182
 181
 220
 282
 292
  
Impairment of long-lived assets—
 —
 292
 92
 25
 7
 9
  
Operating Income416
 526
 415
 448
 315
 486
 1,022
  
Income before income taxes260
 390
 294
 298
 123
 272
 820
  
Income taxes111
 134
 119
 118
 78
 101
 311
  
Net Income149
 256
 175
 180
 45
 171
 509
  
Earnings available to FirstEnergy Corp.155
 265
 179
 185
 50
 181
 511
  
Earnings per share of common stock-               
Basic$0.51
 $0.87
 $0.59
 $0.61
 $0.15
 $0.43
 $1.22
  
Diluted$0.51
 $0.87
 $0.59
 $0.60
 $0.15
 $0.43
 $1.22
  
                
 2010 2011  
Effect of ChangeMar. 31 June 30 Sept. 30 Dec. 31 Mar. 31 June 30 Sept. 30  
Revenues$—
 $—
 $—
 $—
 $—
 $—
 $—
  
Other operating expense(39) (39) (39) (37) (40) (40) (40)  
Pensions and OPEB mark-to-market adjustment—
 —
 —
 190
 —
 —
 —
  
Provision for depreciation5
 5
 5
 7
 5
 5
 5
  
Impairment of long-lived assets—
 —
 3
 1
 —
 —
 —
  
Operating Income34
 34
 31
 (161) 35
 35
 35
  
Income before income taxes34
 34
 31
 (161) 35
 35
 35
  
Income taxes13
 13
 13
 (59) 13
 13
 14
  
Net Income21
 21
 18
 (102) 22
 22
 21
  
Earnings available to FirstEnergy Corp.21
 21
 18
 (102) 22
 22
 21
  
Earnings per share of common stock-               
Basic$0.07
 $0.07
 $0.06
 $(0.34) $0.06
 $0.05
 $0.05
  
Diluted$0.06
 $0.06
 $0.06
 $(0.33) $0.06
 $0.05
 $0.05
  
                
 2010 2011
As RevisedMar. 31 June 30 Sept. 30 Dec. 31 
Mar. 31(1)
 June 30 Sept. 30 Dec. 31
Revenues$3,299
 $3,139
 $3,728
 $3,173
 $3,576
 $4,060
 $4,719
 $3,903
Other operating expense662
 634
 699
 701
 968
 1,058
 984
 899
Pensions and OPEB mark-to-market adjustment—
 —
 —
 190
 —
 —
 —
 507
Provision for depreciation198
 195
 187
 188
 225
 287
 297
 312
Impairment of long-lived assets—
 —
 295
 93
 25
 7
 9
 372
Operating Income450
 560
 446
 287
 350
 521
 1,057
 (230)
Income before income taxes294
 424
 325
 137
 158
 307
 855
 123
Income taxes124
 147
 132
 59
 111
 114
 325
 24
Net Income170
 277
 193
 78
 47
 193
 530
 99
Earnings available to FirstEnergy Corp.176
 286
 197
 83
 52
 203
 532
 98
Earnings per share of common stock-               
Basic$0.58
 $0.94
 $0.65
 $0.27
 $0.15
 $0.48
 $1.27
 $0.23
Diluted$0.57
 $0.93
 $0.65
 $0.27
 $0.15
 $0.48
 $1.27
 $0.23
                
(1) Reflects a $20 million ($0.06 per basic and diluted share of common stock) increase to income taxes related to an Allegheny purchase accounting adjustment identified in the fourth quarter of 2011. FirstEnergy will revise its 2011 quarter filings prospectively when the corresponding 2012 quarters are filed.
                


267


FES               
CONSOLIDATED STATEMENTS OF INCOME        
(In millions)2010 2011  
As ReportedMar. 31 June 30 Sept. 30 Dec. 31 Mar. 31 June 30 Sept. 30  
Revenues$1,388.0
 $1,326.0
 $1,589.0
 $1,525.0
 $1,391.0
 $1,292.0
 $1,467.0
  
Other operating expense305.0
 304.0
 308.0
 363.0
 496.0
 429.0
 405.0
  
Pensions and OPEB mark-to-market adjustment—
 —
 —
 —
 —
 —
 —
  
Provision for depreciation63.0
 63.0
 60.0
 57.0
 68.0
 68.0
 69.0
  
Impairment of long-lived assets2.0
 —
 292.0
 90.0
 14.0
 7.0
 2.0
  
Operating Income (loss)153.0
 215.0
 (46.0) 146.0
 75.0
 48.0
 191.0
  
Income before income taxes124.0
 203.0
 (42.0) 135.0
 56.0
 24.0
 183.0
  
Income taxes44.0
 69.0
 (5.0) 43.0
 20.0
 4.0
 73.0
  
Net Income (loss)80.0
 134.0
 (37.0) 92.0
 36.0
 20.0
 110.0
  
                
 2010 2011  
Effect of ChangeMar. 31 June 30 Sept. 30 Dec. 31 Mar. 31 June 30 Sept. 30  
Revenues$—
 $—
 $—
 $—
 $—
 $—
 $—
  
Other operating expense(12.0) (12.0) (12.0) (14.0) (16.0) (16.0) (15.0)  
Pensions and OPEB mark-to-market adjustment—
 —
 —
 107.0
 —
 —
 —
  
Provision for depreciation1.0
 1.0
 1.0
 —
 1.0
 1.0
 —
  
Impairment of long-lived assets—
 —
 3.0
 1.0
 —
 —
 —
  
Operating Income11.0
 11.0
 8.0
 (94.0) 15.0
 15.0
 15.0
  
Income before income taxes11.0
 11.0
 8.0
 (94.0) 15.0
 15.0
 15.0
  
Income taxes4.0
 4.0
 4.0
 (38.0) 6.0
 6.0
 5.0
  
Net Income7.0
 7.0
 4.0
 (56.0) 9.0
 9.0
 10.0
  
                
 2010 2011
As RevisedMar. 31 June 30 Sept. 30 Dec. 31 Mar. 31 June 30 Sept. 30 Dec. 31
Revenues$1,388.0
 $1,326.0
 $1,589.0
 $1,525.0
 $1,391.0
 $1,292.0
 $1,467.0
 $1,327.0
Other operating expense293.0
 292.0
 296.0
 349.0
 480.0
 413.0
 390.0
 347.0
Pensions and OPEB mark-to-market adjustment—
 —
 —
 107.0
 —
 —
 —
 171.0
Provision for depreciation64.0
 64.0
 61.0
 57.0
 69.0
 69.0
 69.0
 68.0
Impairment of long-lived assets2.0
 —
 295.0
 91.0
 14.0
 7.0
 2.0
 271.0
Operating Income (loss)164.0
 226.0
 (38.0) 52.0
 90.0
 63.0
 206.0
 (340.0)
Income before income taxes135.0
 214.0
 (34.0) 41.0
 71.0
 39.0
 198.0
 (378.0)
Income taxes48.0
 73.0
 (1.0) 5.0
 26.0
 10.0
 78.0
 (125.0)
Net Income (loss)87.0
 141.0
 (33.0) 36.0
 45.0
 29.0
 120.0
 (253.0)
                


268


OE               
CONSOLIDATED STATEMENTS OF INCOME        
(In millions)2010 2011  
As ReportedMar. 31 June 30 Sept. 30 Dec. 31 Mar. 31 June 30 Sept. 30  
Revenues$508.0
 $439.0
 $487.0
 $402.0
 $392.0
 $385.0
 $470.0
  
Other operating expense89.0
 88.0
 95.0
 92.0
 101.0
 111.0
 119.0
  
Pensions and OPEB mark-to-market adjustment—
 —
 —
 —
 —
 —
 —
  
Provision for depreciation22.0
 22.0
 22.0
 22.0
 22.0
 22.0
 23.0
  
Operating Income73.0
 63.0
 90.0
 74.0
 65.0
 72.0
 94.0
  
Income before income taxes56.0
 49.0
 75.0
 58.0
 48.0
 55.0
 83.0
  
Income taxes20.0
 12.0
 29.0
 20.0
 18.0
 16.0
 33.0
  
Net Income36.0
 37.0
 46.0
 38.0
 30.0
 39.0
 50.0
  
                
 2010 2011  
Effect of ChangeMar. 31 June 30 Sept. 30 Dec. 31 Mar. 31 June 30 Sept. 30  
Revenues$—
 $—
 $—
 $—
 $—
 $—
 $—
  
Other operating expense(6.0) (6.0) (6.0) (4.0) (5.0) (5.0) (5.0)  
Pensions and OPEB mark-to-market adjustment—
 —
 —
 24.0
 —
 —
 —
  
Provision for depreciation1.0
 1.0
 1.0
 —
 1.0
 1.0
 —
  
Operating Income5.0
 5.0
 5.0
 (20.0) 4.0
 4.0
 5.0
  
Income before income taxes5.0
 5.0
 5.0
 (20.0) 4.0
 4.0
 5.0
  
Income taxes2.0
 2.0
 2.0
 (9.0) 2.0
 2.0
 1.0
  
Net Income3.0
 3.0
 3.0
 (11.0) 2.0
 2.0
 4.0
  
                
 2010 2011
As RevisedMar. 31 June 30 Sept. 30 Dec. 31 Mar. 31 June 30 Sept. 30 Dec. 31
Revenues$508.0
 $439.0
 $487.0
 $402.0
 $392.0
 $385.0
 $470.0
 $386.0
Other operating expense83.0
 82.0
 89.0
 88.0
 96.0
 106.0
 114.0
 135.0
Pensions and OPEB mark-to-market adjustment—
 —
 —
 24.0
 —
 —
 —
 43.0
Provision for depreciation23.0
 23.0
 23.0
 22.0
 23.0
 23.0
 23.0
 24.0
Operating Income78.0
 68.0
 95.0
 54.0
 69.0
 76.0
 99.0
 23.0
Income before income taxes61.0
 54.0
 80.0
 38.0
 52.0
 59.0
 88.0
 7.0
Income taxes22.0
 14.0
 31.0
 11.0
 20.0
 18.0
 34.0
 6.0
Net Income39.0
 40.0
 49.0
 27.0
 32.0
 41.0
 54.0
 1.0
                


269


CEI              
CONSOLIDATED STATEMENTS OF INCOME      
(In millions)2010 2011  
As ReportedMar. 31 June 30 Sept. 30 Dec. 31 Mar. 31 June 30 Sept. 30  
Revenues$330.1
 $295.7
 $328.7
 $266.9
 $224.9
 $217.9
 $244.0
  
Other operating expense31.2
 28.9
 36.4
 33.4
 35.0
 31.6
 40.3
  
Pensions and OPEB mark-to-market adjustment—
 —
 —
 —
 —
 —
 —
  
Provision for depreciation18.1
 18.3
 18.1
 18.2
 18.4
 18.5
 18.5
  
Operating Income50.3
 56.7
 64.7
 43.7
 43.4
 53.5
 68.8
  
Income before income taxes24.8
 30.7
 38.4
 17.9
 17.6
 28.1
 42.9
  
Income taxes10.8
 8.8
 13.5
 5.6
 4.4
 6.2
 16.3
  
Net Income14.0
 21.9
 24.9
 12.3
 13.2
 21.8
 26.6
  
Earnings available to Parent13.6
 21.6
 24.6
 11.9
 12.8
 21.5
 26.3
  
                
 2010 2011  
Effect of ChangeMar. 31 June 30 Sept. 30 Dec. 31 Mar. 31 June 30 Sept. 30  
Revenues$—
 $—
 $—
 $—
 $—
 $—
 $—
  
Other operating expense(3.7) (3.7) (3.7) (3.7) (3.6) (3.6) (3.6)  
Pensions and OPEB mark-to-market adjustment—
 —
 —
 11.9
 —
 —
 —
  
Provision for depreciation0.5
 0.5
 0.5
 0.6
 0.4
 0.4
 0.4
  
Operating Income3.2
 3.2
 3.2
 (8.8) 3.2
 3.2
 3.2
  
Income before income taxes3.2
 3.2
 3.2
 (8.8) 3.2
 3.2
 3.2
  
Income taxes1.1
 1.1
 1.1
 (6.9) 1.2
 1.2
 1.2
  
Net Income2.1
 2.1
 2.1
 (1.9) 2.0
 2.0
 2.0
  
Earnings available to Parent2.1
 2.1
 2.1
 (1.9) 2.0
 2.0
 2.0
  
                
 2010 2011
As RevisedMar. 31 June 30 Sept. 30 Dec. 31 Mar. 31 June 30 Sept. 30 Dec. 31
Revenues$330.1
 $295.7
 $328.7
 $266.9
 $224.9
 $217.9
 $244.0
 $190.0
Other operating expense27.5
 25.2
 32.7
 29.7
 31.4
 28.0
 36.7
 33.6
Pensions and OPEB mark-to-market adjustment—
 —
 —
 11.9
 —
 —
 —
 20.1
Provision for depreciation18.6
 18.8
 18.6
 18.8
 18.8
 18.9
 18.9
 19.5
Operating Income53.5
 59.9
 67.9
 34.9
 46.6
 56.7
 72.0
 32.0
Income before income taxes28.0
 33.9
 41.6
 9.1
 20.8
 31.3
 46.1
 7.5
Income taxes11.9
 9.9
 14.6
 (1.3) 5.6
 7.4
 17.5
 3.4
Net Income16.1
 24.0
 27.0
 10.4
 15.2
 23.8
 28.6
 4.3
Earnings available to Parent15.7
 23.7
 26.7
 10.0
 14.8
 23.5
 28.3
 4.0
                


270


TE               
CONSOLIDATED STATEMENTS OF INCOME        
(In millions)2010 2011  
As ReportedMar. 31 June 30 Sept. 30 Dec. 31 Mar. 31 June 30 Sept. 30  
Revenues$132.5
 $120.8
 $144.0
 $119.4
 $113.6
 $99.3
 $144.8
  
Other operating expense25.5
 25.5
 28.7
 28.2
 36.6
 32.5
 35.5
  
Pensions and OPEB mark-to-market adjustment—
 —
 —
 —
 —
 —
 —
  
Provision for depreciation8.0
 8.0
 7.8
 7.9
 7.9
 8.0
 8.0
  
Operating Income20.9
 14.4
 27.9
 18.6
 16.6
 20.3
 30.8
  
Income before income taxes12.9
 8.2
 20.0
 9.6
 7.6
 13.0
 23.8
  
Income taxes5.4
 0.9
 6.9
 4.4
 1.7
 1.4
 9.0
  
Net Income7.5
 7.2
 13.1
 5.2
 5.8
 11.6
 14.8
  
Earnings available to Parent7.5
 7.2
 13.1
 5.2
 5.8
 11.6
 14.8
  
                
 2010 2011  
Effect of ChangeMar. 31 June 30 Sept. 30 Dec. 31 Mar. 31 June 30 Sept. 30  
Revenues$—
 $—
 $—
 $—
 $—
 $—
 $—
  
Other operating expense(1.5) (1.5) (1.5) (1.5) (1.5) (1.5) (1.5)  
Pensions and OPEB mark-to-market adjustment—
 —
 —
 4.2
 —
 —
 —
  
Provision for depreciation0.1
 0.1
 0.1
 0.2
 0.1
 0.1
 0.1
  
Operating Income1.4
 1.4
 1.4
 (2.9) 1.4
 1.4
 1.4
  
Income before income taxes1.4
 1.4
 1.4
 (2.9) 1.4
 1.4
 1.4
  
Income taxes0.5
 0.5
 0.5
 (3.4) 0.5
 0.5
 0.5
  
Net Income0.9
 0.9
 0.9
 0.5
 0.9
 0.9
 0.9
  
Earnings available to Parent0.9
 0.9
 0.9
 0.5
 0.9
 0.9
 0.9
  
                
 2010 2011
As RevisedMar. 31 June 30 Sept. 30 Dec. 31 Mar. 31 June 30 Sept. 30 Dec. 31
Revenues$132.5
 $120.8
 $144.0
 $119.4
 $113.6
 $99.3
 $144.8
 $119.3
Other operating expense24.0
 24.0
 27.2
 26.7
 35.1
 31.0
 34.0
 33.3
Pensions and OPEB mark-to-market adjustment—
 —
 —
 4.2
 —
 —
 —
 10.6
Provision for depreciation8.1
 8.1
 7.9
 8.1
 8.0
 8.1
 8.1
 8.3
Operating Income22.3
 15.8
 29.3
 15.7
 18.0
 21.7
 32.2
 8.1
Income before income taxes14.3
 9.6
 21.4
 6.7
 9.0
 14.4
 25.2
 0.7
Income taxes5.9
 1.4
 7.4
 1.0
 2.2
 1.9
 9.5
 1.0
Net Income8.4
 8.1
 14.0
 5.7
 6.7
 12.5
 15.7
 (0.2)
Earnings available to Parent8.4
 8.1
 14.0
 5.7
 6.7
 12.5
 15.7
 (0.2)
                


271


JCP&L               
CONSOLIDATED STATEMENTS OF INCOME        
(In millions)2010 2011  
As ReportedMar. 31 June 30 Sept. 30 Dec. 31 Mar. 31 June 30 Sept. 30  
Revenues$704.0
 $721.0
 $968.0
 $634.0
 $647.0
 $588.0
 $777.0
  
Other operating expense96.0
 75.0
 89.0
 84.0
 86.0
 79.0
 132.0
  
Pensions and OPEB mark-to-market adjustment—
 —
 —
 —
 —
 —
 —
  
Provision for depreciation28.0
 27.0
 27.0
 26.0
 25.0
 27.0
 31.0
  
Operating Income80.0
 112.0
 176.0
 85.0
 66.0
 99.0
 169.0
  
Income before income taxes53.0
 83.0
 147.0
 57.0
 38.0
 72.0
 142.0
  
Income taxes24.0
 34.0
 64.0
 26.0
 18.0
 30.0
 59.0
  
Net Income29.0
 50.0
 83.0
 30.0
 20.0
 42.0
 83.0
  
                
 2010 2011  
Effect of ChangeMar. 31 June 30 Sept. 30 Dec. 31 Mar. 31 June 30 Sept. 30  
Revenues$—
 $—
 $—
 $—
 $—
 $—
 $—
  
Other operating expense(5.0) (5.0) (5.0) (6.0) (6.0) (6.0) (6.0)  
Pensions and OPEB mark-to-market adjustment—
 —
 —
 26.0
 —
 —
 —
  
Provision for depreciation1.0
 1.0
 1.0
 2.0
 1.0
 1.0
 2.0
  
Operating Income4.0
 4.0
 4.0
 (22.0) 5.0
 5.0
 4.0
  
Income before income taxes4.0
 4.0
 4.0
 (22.0) 5.0
 5.0
 4.0
  
Income taxes2.0
 2.0
 2.0
 (7.0) 2.0
 2.0
 2.0
  
Net Income2.0
 2.0
 2.0
 (15.0) 3.0
 3.0
 2.0
  
                
 2010 2011
As RevisedMar. 31 June 30 Sept. 30 Dec. 31 Mar. 31 June 30 Sept. 30 Dec. 31
Revenues$704.0
 $721.0

$968.0

$634.0

$647.0

$588.0

$777.0
 $483.0
Other operating expense91.0
 70.0
 84.0
 78.0
 80.0
 73.0
 126.0
 92.0
Pensions and OPEB mark-to-market adjustment—
 —
 —
 26.0
 —
 —
 —
 60.0
Provision for depreciation29.0
 28.0
 28.0
 28.0
 26.0
 28.0
 33.0
 48.0
Operating Income84.0
 116.0
 180.0
 63.0
 71.0
 104.0
 173.0
 24.0
Income before income taxes57.0
 87.0
 151.0
 35.0
 43.0
 77.0
 146.0
 (5.0)
Income taxes26.0
 36.0
 66.0
 19.0
 20.0
 32.0
 61.0
 4.0
Net Income (Loss)31.0
 52.0
 85.0
 15.0
 23.0
 45.0
 85.0
 (9.0)
                


272


Met-Ed               
CONSOLIDATED STATEMENTS OF INCOME        
(In millions)2010 2011  
As ReportedMar. 31 June 30 Sept. 30 Dec. 31 Mar. 31 June 30 Sept. 30  
Revenues$473.1
 $442.7
 $483.9
 $418.8
 $357.2
 $280.0
 $316.4
  
Other operating expense102.0
 90.2
 141.8
 84.6
 47.2
 50.1
 47.5
  
Pensions and OPEB mark-to-market adjustment—
 —
 —
 —
 —
 —
 —
  
Provision for depreciation12.8
 13.4
 13.0
 13.0
 12.4
 12.8
 14.5
  
Operating Income34.8
 36.3
 35.1
 37.9
 40.4
 42.0
 49.8
  
Income before income taxes24.6
 25.7
 24.3
 26.2
 28.5
 30.1
 38.1
  
Income taxes12.3
 8.6
 10.1
 11.8
 5.9
 13.3
 13.0
  
Net Income12.3
 17.1
 14.2
 14.4
 22.6
 16.8
 25.1
  
                
 2010 2011  
Effect of ChangeMar. 31 June 30 Sept. 30 Dec. 31 Mar. 31 June 30 Sept. 30  
Revenues$—
 $—
 $—
 $—
 $—
 $—
 $—
  
Other operating expense(4.4) (4.4) (4.4) (4.4) (3.8) (3.8) (3.7)  
Pensions and OPEB mark-to-market adjustment—
 —
 —
 7.0
 —
 —
 —
  
Provision for depreciation0.9
 0.9
 0.9
 0.9
 0.8
 0.8
 0.9
  
Operating Income3.5
 3.5
 3.5
 (3.5) 3.0
 3.0
 2.8
  
Income before income taxes3.5
 3.5
 3.5
 (3.5) 3.0
 3.0
 2.8
  
Income taxes1.5
 1.5
 1.5
 0.4
 1.2
 1.2
 1.2
  
Net Income2.0
 2.0
 2.0
 (3.9) 1.8
 1.8
 1.6
  
                
 2010 2011
As RevisedMar. 31 June 30 Sept. 30 Dec. 31 Mar. 31 June 30 Sept. 30 Dec. 31
Revenues$473.1
 $442.7
 $483.9
 $418.8
 $357.2
 $280.0
 $316.4
 $258.9
Other operating expense97.6
 85.8
 137.4
 80.2
 43.4
 46.3
 43.8
 37.7
Pensions and OPEB mark-to-market adjustment—
 —
 —
 7.0
 —
 —
 —
 33.5
Provision for depreciation13.7
 14.3
 13.9
 13.9
 13.2
 13.6
 15.4
 18.6
Operating Income38.3
 39.8
 38.6
 34.4
 43.4
 45.0
 52.6
 12.2
Income before income taxes28.1
 29.2
 27.8
 22.7
 31.5
 33.1
 40.9
 (0.8)
Income taxes13.8
 10.1
 11.6
 12.2
 7.1
 14.5
 14.2
 1.0
Net Income14.3
 19.1
 16.2
 10.5
 24.4
 18.6
 26.7
 (1.8)
                


273


Penelec               
CONSOLIDATED STATEMENTS OF INCOME        
(In millions)2010 2011  
As ReportedMar. 31 June 30 Sept. 30 Dec. 31 Mar. 31 June 30 Sept. 30  
Revenues$403.5
 $366.5
 $389.9
 $380.0
 $324.8
 $251.7
 $261.5
  
Other operating expense72.4
 67.1
 58.8
 70.3
 41.3
 44.6
 39.0
  
Pensions and OPEB mark-to-market adjustment—
 —
 —
 —
 —
 —
 —
  
Provision for depreciation14.7
 16.6
 14.9
 15.1
 14.6
 15.8
 16.1
  
Operating Income50.0
 34.9
 41.0
 37.9
 46.3
 45.0
 48.0
  
Income before income taxes34.5
 18.8
 25.1
 22.2
 29.1
 28.3
 31.4
  
Income taxes17.2
 5.8
 5.3
 12.8
 11.8
 13.6
 11.3
  
Net Income17.3
 13.0
 19.8
 9.4
 17.3
 14.7
 20.2
  
                
 2010 2011  
Effect of ChangeMar. 31 June 30 Sept. 30 Dec. 31 Mar. 31 June 30 Sept. 30  
Revenues$—
 $—
 $—
 $—
 $—
 $—
 $—
  
Other operating expense(5.4) (5.4) (5.4) (5.4) (4.3) (4.3) (4.3)  
Pensions and OPEB mark-to-market adjustment—
 —
 —
 8.3
 —
 —
 —
  
Provision for depreciation1.1
 1.1
 1.1
 1.1
 1.0
 1.0
 1.0
  
Operating Income4.3
 4.3
 4.3
 (4.0) 3.3
 3.3
 3.3
  
Income before income taxes4.3
 4.3
 4.3
 (4.0) 3.3
 3.3
 3.3
  
Income taxes1.8
 1.8
 1.8
 (0.2) 1.4
 1.4
 1.4
  
Net Income2.5
 2.5
 2.5
 (3.8) 1.9
 1.9
 1.9
  
                
 2010 2011
As RevisedMar. 31 June 30 Sept. 30 Dec. 31 Mar. 31 June 30 Sept. 30 
Dec. 31(1)
Revenues$403.5
 $366.5
 $389.9
 $380.0
 $324.8
 $251.7
 $261.5
 $243.2
Other operating expense67.0
 61.7
 53.4
 64.9
 37.0
 40.3
 34.7
 36.3
Pensions and OPEB mark-to-market adjustment—
 —
 —
 8.3
 —
 —
 —
 41.1
Provision for depreciation15.8
 17.7
 16.0
 16.2
 15.6
 16.8
 17.1
 13.6
Operating Income54.3
 39.2
 45.3
 33.9
 49.6
 48.3
 51.3
 10.3
Income before income taxes38.8
 23.1
 29.4
 18.2
 32.4
 31.6
 34.7
 (5.5)
Income taxes19.0
 7.6
 7.1
 12.6
 13.2
 15.0
 12.7
 (10.8)
Net Income19.8
 15.5
 22.3
 5.6
 19.2
 16.6
 22.1
 5.2
                
(1) The fourth quarter of 2011 reflects a $4.6 million decrease to income taxes to correct a deferred tax valuation allowance related to periods prior to 2009.

     Operating  
Income (Loss)
Before
  Income  Earnings 
     Income  Income  Taxes  Available To 
Three Months Ended Revenues  (Loss)  Taxes  (Benefit)   FirstEnergy 
  (In millions) 
FE               
March 31, 2009 $3,334.0  $346.0  $169.0  $54.0  $119.0 
March 31, 2008  3,277.0   618.0   464.0   187.0   276.0 
June 30, 2009  3,271.0   802.0   656.0   248.0   414.0 
June 30, 2008  3,245.0   582.0   423.0   160.0   263.0 
September 30,2009  3,408.0   487.0   358.0   128.0   234.0 
September 30,2008  3,904.0   846.0   709.0   238.0   471.0 
December 31, 2009  2,954.0   244.0   52.0   (185.0)  239.0 
December 31, 2008  3,201.0   713.0   520.0   192.0   332.0 
                     
FES                    
March 31, 2009 $1,226.1  $304.3  $262.5  $91.8  $170.7 
March 31, 2008  1,099.1   175.7   147.8   57.8   90.0 
June 30, 2009  1,341.2   468.9   466.6   169.2   297.4 
June 30, 2008  1,071.3   142.2   115.4   47.3   68.1 
September 30,2009  1,104.6   175.7   310.8   111.2   199.7 
September 30,2008  1,241.6   288.8   278.9   93.2   185.7 
December 31, 2009  1,056.4   (96.3)  (147.5)  (56.9)  (90.7)
December 31, 2008  1,106.4   311.6   257.5   94.9   162.6 
                     
OE                    
March 31, 2009 $749.0  $30.2  $15.7  $4.0  $11.5 
March 31, 2008  652.6   77.1   70.9   26.9   43.9 
June 30, 2009  672.2   58.8   50.5   16.9   33.5 
June 30, 2008  609.6   76.1   70.7   21.7   48.8 
September 30,2009  602.5   52.8   50.6   15.9   34.6 
September 30,2008  702.3   100.0   101.1   28.5   72.5 
December 31, 2009 *  493.2   87.1   71.8   29.4   42.3 
December 31, 2008  637.3   80.8   68.2   21.5   46.5 
                     
CEI                    
March 31, 2009 $449.7  $(144.1) $(166.9) $(61.5) $(105.9)
March 31, 2008  437.3   110.8   88.8   30.3   57.9 
June 30, 2009  475.1   98.5   74.2   26.5   47.3 
June 30, 2008  434.4   123.4   100.8   33.8   66.6 
September 30,2009  435.5   61.6   35.1   9.8   25.0 
September 30,2008  524.1   159.9   136.8   43.0   93.4 
December 31, 2009  315.8   64.7   36.4   15.0   20.9 
December 31, 2008  420.1   120.5   96.9   29.7   66.6 
                     
* Includes a $4.8 million adjustment that increased net income in the fourth quarter of 2009 related to prior periods.  
(See Note 10 for description of adjustment).  

252
     Operating  
Income (Loss)
Before
  Income  Earnings 
     Income  Income  Taxes  Available To 
Three Months Ended Revenues  (Loss)  Taxes  (Benefit)  FirstEnergy 
  (In millions) 
TE               
March 31, 2009 $244.8  $2.2  $0.9  $(0.1) $1.0 
March 31, 2008  211.7   26.1   25.1   8.1   17.0 
June 30, 2009  226.2   10.1   9.8   3.4   6.4 
June 30, 2008  221.5   30.9   28.7   7.4   21.3 
September 30,2009  213.5   10.2   7.0   (0.1)  7.1 
September 30,2008  251.1   45.1   43.4   12.2   31.2 
December 31, 2009 **  149.4   23.8   14.2   4.7   9.5 
December 31, 2008  211.2   10.8   7.6   2.1   5.4 
                     
Met-Ed                    
March 31, 2009 $429.7  $37.7  $28.4  $11.7  $16.6 
March 31, 2008  400.3   45.6   38.9   16.7   22.2 
June 30, 2009  377.6   27.8   17.0   7.0   10.0 
June 30, 2008  392.0   37.8   32.7   12.9   19.8 
September 30,2009  445.5   24.2   13.1   2.3   10.7 
September 30,2008  455.5   45.1   38.3   16.3   22.0 
December 31, 2009  436.2   37.2   25.6   7.6   18.2 
December 31, 2008  405.2   46.1   39.0   15.0   24.0 
                     
Penelec                    
March 31, 2009 $388.6  $44.2  $31.8  $13.1  $18.7 
March 31, 2008  395.5   56.0   39.7   18.3   21.4 
June 30, 2009  331.7   36.0   25.1   10.2   14.8 
June 30, 2008  351.4   44.2   30.4   12.0   18.4 
September 30,2009  355.5   32.3   21.8   6.0   15.8 
September 30,2008  389.8   46.6   31.7   9.1   22.6 
December 31, 2009  373.1   49.4   32.4   16.4   16.1 
December 31, 2008  376.9   57.7   44.0   18.2   25.8 
                     
JCP&L                    
March 31, 2009 $773.7  $77.1  $50.1  $22.6  $27.6 
March 31, 2008  794.2   86.9   62.4   28.4   34.0 
June 30, 2009  708.1   95.4   67.9   29.8   38.1 
June 30, 2008  834.7   97.4   74.4   31.5   42.9 
September 30,2009  868.2   133.7   105.6   43.4   62.2 
September 30,2008  1,102.6   157.7   131.7   55.8   75.9 
December 31, 2009  642.7   84.1   55.7   13.0   42.6 
December 31, 2008  740.8   92.5   66.7   32.5   34.2 
  
** Includes a $2.5 million adjustment that increased net income in the fourth quarter of 2009 related to prior periods.  
(See Note 10 for description of adjustment).  
253

21.SUBSEQUENT EVENTS

On February 11, 2010, FirstEnergy and Allegheny Energy, Inc. (Allegheny) announced that both companies' boards of directors unanimously approved a definitive agreement in which the companies would combine in a stock-for-stock transaction.274

Under the terms of the agreement, Allegheny shareholders would receive 0.667 of a share of FirstEnergy common stock in exchange for each share of Allegheny they own. Based on the closing stock prices for both companies on February 10, 2010, Allegheny shareholders would receive a value of $27.65 per share, or $4.7 billion in the aggregate. FirstEnergy would also assume approximately $3.8 billion of Allegheny net debt.
The merger is conditioned upon, among other things, the approval of the shareholders of both companies, 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 Maryland Public Service Commission, the PPUC, the Virginia State Corporation Commission and the West Virginia Public Service Commission. The merger is also conditioned on effectiveness at the SEC of FirstEnergy’s registration statement with respect to the shares to be issued in the transaction. The companies anticipate that the necessary approvals may be obtained within 12-14 months.

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. As a result, FirstEnergy may be required to post up to $48 million of collateral (see Note 15(B)). Moody's and Fitch affirmed the ratings and stable outlook of FirstEnergy and its subsidiaries on February 11, 2010. These rating agency actions were taken in response to the announcement of the proposed merger with Allegheny.

254

ITEM 9.     CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.

ITEM 9A.  CONTROLS AND PROCEDURES -- FIRSTENERGY

ITEM 9A.CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures

FirstEnergy's Chief Executive OfficerThe management of FirstEnergy, FES, OE, CEI, TE JCP&L, Met-Ed and Chief Financial OfficerPenelec, with the participation of each registrant's chief executive officer and chief financial officer, each have reviewed and evaluated such registrant’sthe effectiveness of the registrant's disclosure controls and procedures, as defined in the Securities Exchange Act of 1934, as amended, Rules 13a-15(e) and 15d-15(e), as of the end dateof the period covered by this report. Based upon thison that evaluation, the Chief Executive Officerchief executive officer and Chief Financial Officerchief financial officer of each registrant have concluded that FirstEnergy'seach respective registrant's disclosure controls and procedures were effective as of December 31, 2009.

the end of the period covered by this report.
Management’s Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control –— Integrated Framework management conducted an evaluation of the effectiveness of FirstEnergy's internal control over financial reporting under the supervision of FirstEnergy's Chief Executive Officer and Chief Financial Officer. Based on that evaluation, management concluded that FirstEnergy's internal control over financial reporting was effective as of December 31, 2009. The effectiveness of FirstEnergy's internal control over financial reporting, as of December 31, 2009, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report included herein.

Changes in Internal Control over Financial Reporting

There were no changes in FirstEnergy's internal control over financial reporting during the fourth quarter of 2009 that have materially affected, or are reasonably likely to materially affect, FirstEnergy's internal control over financial reporting.

ITEM 9A(T). CONTROLS AND PROCEDURES --FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec

Evaluation of Disclosure Controls and Procedures

Each registrant's Chief Executive Officer and Chief Financial Officer have reviewed and evaluated such registrant's disclosure controls and procedures, as defined in the Securities Exchange Act of 1934 rules 13a-15(e) and 15d-15(e), as of the end date covered by this report. Based upon this evaluation, the respective Chief Executive Officer and Chief Financial Officer concluded that such registrant's disclosure controls and procedures were effective as of December 31, 2009.

Management’s Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework, management conducted an evaluation of the effectiveness of each registrant’s internal control over financial reporting under the supervision of sucheach registrant’s Chief Executive Officer and Chief Financial Officer. Based on that evaluation, management concluded that each registrant’s internal control over financial reporting was effective as of December 31, 2009.2011. The effectiveness of each registrant'sFirstEnergy’s internal control over financial reporting, as of December 31, 2009,2011, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report included herein. The effectiveness of internal control over financial reporting of FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec, as of December 31, 2011, has not been audited by such registrant’sthe registrants’ independent registered public accounting firm.

Changes in Internal Control over Financial Reporting

There wereDuring the quarter ended December 31, 2011, other than changes resulting from the Allegheny merger discussed below, there have been no changes in internal control over financial reporting during the fourth quarter of 2009 that have materially affected, or are reasonably likely to materially affect, FirstEnergy's, FES', OE's, CEI's, TE's, JCP&L's, Met-Ed's and Penelec's internal control over financial reportingreporting.
On February 25, 2011, the merger between FirstEnergy and Allegheny closed. FirstEnergy is currently in the process of integrating Allegheny's operations, processes, and internal controls. See Note 2, Merger of the Combined Notes to the Consolidated Financial Statements for each registrant.additional information relating to the merger.
ITEM 9B.    OTHER INFORMATION
ITEM 9B.OTHER INFORMATION

None.

255

PART III

ITEM 10.    DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by Item 10 with respect to identification of FirstEnergy’s directors and with respect to reports required to be filed under Section 16 of the Securities Exchange Act of 1934, is incorporated herein by reference to FirstEnergy’s 2010FirstEnergy's 2012 Proxy Statement filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934 and, with respect to identification of executive officers, to “Part I, Item 1. Business – Executive Officers” herein.

The Board of Directors, upon recommendation of the Corporate Governance and Audit Committees, has determined that Ernest J. Novak, Jr., an independent director, is the audit committee financial expert.

FirstEnergy makes available on its Web site at http://www.firstenergycorp.com/ir its Corporate Governance Policies and the charters for each of the following committees of the Board of Directors: Audit; Corporate Governance; Compensation; Finance; and Nuclear.

FirstEnergy has adopted a Code of Business Conduct, which applies to all employees, including the Chief Executive Officer, the Chief Financial Officer and the Chief Accounting Officer. In addition, the Board of Directors has its own Code of Business Conduct. These Codes can be found on the Web site provided in the previous paragraph.

ITEM 11.EXECUTIVE COMPENSATION

The information required by Item 11 is incorporated herein by reference to FirstEnergy’s 2010 Proxy Statement filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.
ITEM 11.EXECUTIVE COMPENSATION

The information required by Item 11 is incorporated herein by reference to FirstEnergy’s 2012 Proxy Statement to be filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.
ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required by Item 12 is incorporated herein by reference to FirstEnergy’s 20102012 Proxy Statement to be filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.

ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by Item 13 is incorporated herein by reference to FirstEnergy’s 20102012 Proxy Statement to be filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.
ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICES


ITEM 14.    PRINCIPAL ACCOUNTING FEES AND SERVICES275


A summary of the audit and audit-related fees for services rendered by PricewaterhouseCoopers LLP for the years ended December 31, 20092011 and 20082010, are as follows:

 
Audit Fees(1)
  
Audit-Related Fees
  
Audit Fees(1)
 
Audit-Related Fees(2)
Company
 
2009
  
2008
  
2009
  
2008
  2011 2010 2011 2010
 (In thousands)  (In thousands)
FES $991  $835  $-  $-  $1,192
 $1,181
 $—
 $—
OE  1,019   1,155   -   -  630
 636
 —
 —
CEI  734   764   -   -  540
 542
 75
 —
TE  626   598   -   -  630
 589
 —
 —
JCP&L  715   682   -   -  630
 589
 75
 —
Met-Ed  607   583   -   -  510
 495
 75
 —
Penelec  613   595   -   -  510
 495
 —
 —
Other subsidiaries  690   607   -   - 
FE and other subsidiaries 2,723
 976
 63
 548
Total FirstEnergy $5,995  $5,819  $-  $-  $7,365
 $5,503
 $288
 $548
(1)
Professional services rendered for the audits of FirstEnergy’sthe Registrants' annual financial statements and reviews of unaudited financial statements included in FirstEnergy’sthe Registrants' Quarterly Reports on Form 10-Q and for services in connection with statutory and regulatory filings or engagements, including comfort letters and consents for financings and filings made with the SEC.
(2)
Professional services rendered in 2011 related to additional agreed upon procedures that included the audit of compliance with certain DOE grants and the audit of PE's cost allocation manual. Professional services rendered in 2010 related to AE merger due diligence activities.
Tax and Other Fees
There were no other feesPricewaterhouseCoopers LLP billed to FirstEnergy $22,566 for tax orservices in 2011 related to a tax feasibility analysis on bonus depreciation for the Sammis Air Quality Control Project and $134,000 in 2010 for tax services related to the preparation and support of Signal Peak and Global Rail tax returns. PriceWaterhouseCoopers, LLC performed no other services for the years ended December 31, 2009 and 2008.

in 2011 or 2010.
Additional information required by this item is incorporated herein by reference to FirstEnergy's 2010FirstEnergy’s 2012 Proxy Statement to be filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.


276
256


PART IV

ITEM 15.    EXHIBITS, FINANCIAL STATEMENT SCHEDULES

ITEM 15.EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a) The following documents are filed as a part of this report on Form 10-K:

1. Financial Statements:

Management'sManagement’s Report on Internal Control Over Financial Reporting for FirstEnergy Corp., FES, OE, CEI, TE, JCP&L, Met-Ed, and Penelec is listed under Item 8 herein.

Reports of Independent Registered Public Accounting Firm for FirstEnergy Corp., FES, OE, CEI, TE, JCP&L, Met-Ed, and Penelec are listed under Item 8 herein.

The financial statements filed as a part of this report for FirstEnergy Corp., FES, OE, CEI, TE, JCP&L, Met-Ed, and Penelec are listed under Item 8 herein.

2. Financial Statement Schedules:

Reports of Independent Registered Public Accounting Firm as to Schedules for FirstEnergy Corp., FES, OE, CEI, TE, JCP&L, Met-Ed, and Penelec are included herein on pages 140, 141, 142, 143, 144, 145, 146 and 147.pages:

Page
FirstEnergy
137
FES
138
OE
139
CEI
140
TE
141
JCP&L
142
Met-Ed
143
Penelec
144
Schedule II –— Consolidated Valuation and Qualifying Accounts for FirstEnergy Corp., FES, OE, CEI, TE, JCP&L, Met-Ed, and Penelec are included herein on pages 302, 303, 304, 305, 306, 307, 308 and 309.pages:
Page
FirstEnergy
311
FES
312
OE
313
CEI
314
TE
315
JCP&L
316
Met-Ed
317
Penelec
318

3.    Exhibits – FirstEnergy

Exhibit
Number

3. Exhibits — FirstEnergy
Exhibit
Number
2-1†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 FE’s Form 8-K filed February 11, 2010, Exhibit 2.1, File No. 333-21011)
  
(A) 3-1Amended Articles of Incorporation of FirstEnergy Corp. (incorporated by reference to FE’s Form 10-K filed February 19, 2010, Exhibit 3-1, File No. 333-21011)
  
3-2Amendment to the Amended Articles of Incorporation of FirstEnergy Corp. dated as of February 25, 2011 (incorporated by reference to FE’s Form 8-K filed February 25, 2011, Exhibit 3.1, File No. 333-21011)
3-3FirstEnergy Corp. Amended Code of Regulations. (incorporated by referencereferences to FE’sFE's Form 10-K filed February 25, 2009, Exhibit 3.1, File No. 333-21011)
  


277



Exhibit
Number
4-1Indenture, dated November 15, 2001, between FirstEnergy Corp. and The Bank of New York Mellon, as Trustee. (incorporated by reference to FE’s Form S-3 filed September 21, 2001, Exhibit 4(a), File No. 333-69856)
  
(B) 10-1FirstEnergy Corp. 2007 Incentive Plan, effective May 15, 2007. (incorporated by reference to FE’s Form 10-K filed February 25, 2009, Exhibit 10.1, File No. 333-21011)
  
(B) 10-2Amendment to FirstEnergy Corp. 2007 Incentive Compensation Plan, effective January 1, 2011. (incorporated by reference to FE's Form 10-Q filed May 3, 2011, Exhibit 10.5, File No. 333-21011)
 
(B) 10-210-3Amended FirstEnergy Corp. Deferred Compensation Plan for Outside Directors, amended and restated as of January 1, 2005 and ratified as of September 18, 2007. (incorporated by reference to FE’s Form 10-K filed February 25, 2009, Exhibit 10.2, File No. 333-21011)
  
(B) 10-310-4Amendment to FirstEnergy Corp. Deferred Compensation Plan for Outside Directors, effective January 1, 2012. (incorporated by reference to FE's Form 10-Q filed May 3, 2011, Exhibit 10.7, File No. 333-21011)
(B) 10-5FirstEnergy Corp. Supplemental Executive Retirement Plan, amended January 1, 1999. (incorporated by reference to FE’s Form 10-K filed March 20, 2000, Exhibit 10-4, File No. 333-21011)
  
(B) 10-410-6Amendment to FirstEnergy Corp. Supplemental Executive Retirement Plan, effective January 1, 2012. (incorporated by reference to FE's Form 10-Q filed May 3, 2011, Exhibit 10.8, File No. 333-21011)
(B) 10-7Stock Option Agreement between FirstEnergy Corp. and officers dated November 22, 2000. (incorporated by reference to FE’s Form 10-K filed March 28, 2001, Exhibit 10-3, File No. 333-21011)
  
(B) 10-510-8Stock Option Agreement between FirstEnergy Corp. and officers dated March 1, 2000. (incorporated by reference to FE’s Form 10-K filed March 28, 2001, Exhibit 10-4, File No. 333-21011)
  
(B) 10-610-9Stock Option Agreement between FirstEnergy Corp. and director dated January 1, 2000. (incorporated by reference to FE’s Form 10-K filed March 28, 2001, Exhibit 10-5, File No. 333-21011)

257
(B) 10-710-10Stock Option Agreement between FirstEnergy Corp. and two directors dated January 1, 2001. (incorporated by reference to FE’s Form 10-K filed March 28, 2001, Exhibit 10-6, File No. 333-21011)
  
(B) 10-810-11Stock Option Agreements between FirstEnergy Corp. and One Director dated January 1, 2002. (incorporated by reference to FE’s Form 10-K filed April 1, 2002, Exhibit 10-5, File No. 333-21011)
  
(B) 10-910-12FirstEnergy Corp. Executive Deferred Compensation Plan, amended and restated as of January 1, 2005 and ratified as of September 18, 2007. (incorporated by reference to FE’s 10-Q filed October 31, 2007, Exhibit 10.2, File No. 333-21011)
  
(B) 10-1010-13Amendment to FirstEnergy Corp. Executive Deferred Compensation Plan, effective January 1, 2012. (incorporated by reference to FE's Form 10-Q filed May 3, 2011, Exhibit 10.6, File No. 333-21011)
(B) 10-14Executive Incentive Compensation Plan-Tier 2. (incorporated by reference to FE’s Form 10-K filed April 1, 2002, Exhibit 10-7, File No. 333-21011)
  
(B) 10-1110-15Executive Incentive Compensation Plan-Tier 3. (incorporated by reference to FE’s Form 10-K filed April 1, 2002, Exhibit 10-8, File No. 333-21011)
  
(B) 10-1210-16Executive Incentive Compensation Plan-Tier 4. (incorporated by reference to FE’s Form 10-K filed April 1, 2002, Exhibit 10-9, File No. 333-21011)
  
(B) 10-1310-17Executive Incentive Compensation Plan-Tier 5. (incorporated by reference to FE’s Form 10-K filed April 1, 2002, Exhibit 10-10, File No. 333-21011)
  
(B) 10-1410-18Amendment to GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries, effective April 5, 2001. (incorporated by reference to FE’s Form 10-K filed April 1, 2002, Exhibit 10-11, File No. 333-21011)
  
(B) 10-1510-19Form of Amendment, effective November 7, 2001, to GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries, Deferred Remuneration Plan for Outside Directors of GPU, Inc., and Retirement Plan for Outside Directors of GPU, Inc. (incorporated by reference to FE’s Form 10-K filed April 1, 2002, Exhibit 10-12, File No. 333-21011)
  
(B) 10-1610-20GPU, Inc. Stock Option and Restricted Stock Plan for MYR Group, Inc. Employees. (incorporated by reference to FE’s Form 10-K filed April 1, 2002, Exhibit 10-13, File No. 333-21011, File No. 333-21011)
  


278



Exhibit
Number
(B) 10-1710-21Executive and Director Stock Option Agreement dated June 11, 2002. (incorporated by reference to FE’s Form 10-K, Exhibit 10-1, File No. 333-21011)
  
(B) 10-1810-22Director Stock Option Agreement. (incorporated by reference to FE’s Form 10-K filed March 26, 2003, Exhibit 10-2, File No. 333-21011)
  
(B) 10-1910-23Executive Incentive Compensation Plan 2002. (incorporated by reference to FE’s Form 10-K filed March 26, 2003, Exhibit 10-28, File No. 333-21011)
  
(B) 10-2010-24GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries as amended and restated to reflect amendments through June 3, 1999. (incorporated by reference to GPU, Inc. Form 10-K filed March 20, 2000, Exhibit 10-V, File No. 001-06047)
  
(B) 10-2110-25Form of 1998 Stock Option Agreement under the GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries. (incorporated by reference to GPU, Inc. Form 10-K filed March 20, 2000, Exhibit 10-Q, File No. 001-06047)
  
(B) 10-2210-26Form of 1999 Stock Option Agreement under the GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries. (incorporated by reference to GPU, Inc. Form 10-K filed March 20, 2000, Exhibit 10-W, File No. 001-06047)
  
(B) 10-2310-27Form of 2000 Stock Option Agreement under the GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries. (incorporated by reference to GPU, Inc. Form 10-K filed March 20, 2000, Exhibit 10-W, File No. 001-06047)

258
(B) 10-2410-28Deferred Remuneration Plan for Outside Directors of GPU, Inc. as amended and restated effective August 8, 2000. (incorporated by reference to GPU, Inc. Form 10-K filed March 20, 2000, Exhibit 10-O, File No. 001-06047)
  
(B) 10-2510-29Retirement Plan for Outside Directors of GPU, Inc. as amended and restated as of August 8, 2000. (incorporated by reference to GPU, Inc. Form 10-K filed March 20, 2000, Exhibit 10-N, File No. 001-06047)
  
(B) 10-2610-30Forms of Estate Enhancement Program Agreements entered into by certain former GPU directors. (incorporated by reference to GPU, Inc. Form 10-K filed March 20, 2000, Exhibit 10-JJ, File No. 001-06047)
  
(A)(B) 10-27Employment Agreement for Richard R. Grigg dated February 26, 2008, (incorporated by reference to FE’s Form 10-K filed February 29, 2008, Exhibit 10.5, File No. 333-21011),  as amended on January 29, 2010.
 
(B) 10-2810-31Stock Option Agreement between FirstEnergy Corp. and an officer dated August 20, 2004. (incorporated by reference to FE’s Form 10-Q filed November 4, 2004, Exhibit 10-42, File No. 333-21011)
  
(B) 10-2910-32Executive Bonus Plan between FirstEnergy Corp. and Officers effective November 3, 2004. (incorporated by reference to FE’s Form 10-Q filed November 4, 2004, Exhibit 10-44, File No. 333-21011)
  
10-3010-33Consent Decree dated March 18, 2005. (incorporated by reference to FE’s Form 8-K filed March 18, 2005, Exhibit 10-1, File No. 333-21011)
  
(C) 10-31Form of Guaranty Agreement dated as of December 16, 2005 between FirstEnergy Corp. and FirstEnergy Solutions Corp. in Favor of Barclays Bank PLC as Administrative Agent for the Banks. (incorporated by reference to FE’s Form 10-K filed March 3, 2006, Exhibit 10-1, File No. 333-21011)
 
(D) 10-32(C) 10-34Form of Guaranty Agreement dated as of April 3, 2006 by FirstEnergy Corp. in favor of the Participating Banks, Barclays Bank PLC, as administrative agent and fronting bank, and KeyBank National Association, as syndication agent, under the related Letter of Credit and Reimbursement Agreement. (incorporated by reference to FE’s Form 10-Q filed May 9, 2006, Exhibit 10-1, File No. 333-21011)
  
(B) 10-3310-35Form of Restricted Stock Agreement between FirstEnergy Corp. and A. J. Alexander, dated February 27, 2006. (incorporated by reference to FE’s Form 10-Q filed May 9, 2006, Exhibit 10-6, File No. 333-21011)
  
(B) 10-3410-36Form of Restricted Stock Unit Agreement (Performance Adjusted) between FirstEnergy Corp. and A. J. Alexander, dated March 1, 2006. (incorporated by reference to FE’s Form 10-Q filed May 9, 2006, Exhibit 10-7, File No. 333-21011)
  
(B) 10-3510-37Form of Restricted Stock Unit Agreement (Performance Adjusted) between FirstEnergy Corp. and named executive officers, dated March 1, 2006. (incorporated by reference to FE’s Form 10-Q filed May 9, 2006, Exhibit 10-8, File No. 333-21011)
  
(B) 10-3610-38Form of Restricted Stock Unit Agreement (Performance Adjusted) between FirstEnergy Corp. and R. H. Marsh, dated March 1, 2006. (incorporated by reference to FE’s Form 10-Q filed May 9, 2006, Exhibit 10-9, File No. 333-21011)
  
10-37Confirmation dated March 1, 2007 between FirstEnergy Corp. and Morgan Stanley and Co., International Limited. (incorporated by reference to FE’s Form 10-Q filed May 9, 2007, Exhibit 10.1, File No. 333-21011)
 
(B) 10-3810-39FirstEnergy Corp. Supplemental Executive Retirement Plan as amended September 18, 2007. (incorporated by reference to FE’s Form 10-Q filed October 31, 2007, Exhibit 10.2, File No. 333-21011)

259

(A)
(B) 10-3910-40Employment Agreement between FirstEnergy Corp. and Gary R. Leidich, dated February 26, 2008 (incorporated by reference to FE’s Form 10-K filed February 29, 2008, Exhibit 10-88, File No. 333-21011), as amended on January 29, 2010. (incorporated by reference to FE’s Form 10-K filed February 19, 2010, Exhibit 10-39, File No. 333-21011)


279



Exhibit
Number
  
(B) 10-4010-41Amendment to Employment Agreement, dated February 25,2011, between FirstEnergy Service Company and Gary R. Leidich. (incorporated by reference to FE's Form 10-Q filed May 3, 2011, Exhibit 10.10, File No. 333-21011)
(B) 10-42Form of Restricted Stock Unit Agreement for Gary R. Leidich (per Employment Agreement dated February 26, 2008). (incorporated by reference to FE’s Form 10-K filed February 29, 2008, Exhibit 10-90, File No. 333-21011)
  
(B) 10-4110-43Form of Restricted Stock Agreement Amendment for Gary R. Leidich dated February 26, 2008. (incorporated by reference to FE’s Form 10-K filed February 29, 2008, Exhibit 10-91, File No. 333-21011)
  
(B) 10-42Form of Restricted Stock Unit Agreement for Richard R. Grigg (per Employment Agreement dated February 26, 2008). (incorporated by reference to FE’s Form 10-K filed February 29, 2008, Exhibit 10-92, File No. 333-21011)
 
(B) 10-4310-44Form of Performance-Adjusted Restricted Stock Unit Award Agreement as of March 3, 2008. (incorporated by reference to FE’s Form 10-K filed February 29, 2008, Exhibit 10-93, File No. 333-21011)
  
(B) 10-4410-45Form of 2008-2010 Performance Share Award Agreement effective January 1, 2008. (incorporated by reference to FE’s Form 10-K filed February 29, 2008, Exhibit 10-94, File No. 333-21011)
  
10-45U.S. $300,000,000 Credit Agreement, dated as of October 8, 2008, among FirstEnergy Generation Corp., as Borrower, FirstEnergy Corp. and FirstEnergy Solutions Corp., as Guarantors, Credit Suisse and the other Banks parties thereto from time to time, as Banks and Credit Suisse, as Administrative Agent. (incorporated by reference to FE’s Form 10-Q filed November 7, 2008, Exhibit 10.1, File No. 333-21011)
 
(B) 10-46Form of 2009-2011 Performance Share Award Agreement effective January 1, 2009 (incorporated by reference to FE'sFE’s Form 10-K filed February 25, 2009, Exhibit 10-48, File No. 333-21011)
  
(B) 10-47Form of Performance-Adjusted Restricted Stock Unit Award Agreement as of March 2, 2009 (incororaetd(incorporated by reference to FE'sFE’s Form 10-K filed February 25, 2009, Exhibit 10-49, File No. 333-21011)
  
(A)(B) 10-48Form of 2010-2012 Performance Share Award Agreement effective January 1, 2010 (incorporated by reference to FE’s Form 10-K filed February 19, 2010, Exhibit 10-48, File No. 333-21011)
  
(A)(B) 10-49Form of Performance-Adjusted Restricted Stock Unit Award Agreement as of March 8, 2010 (incorporated by reference to FE’s Form 10-K filed February 19, 2010, Exhibit 10-49, File No. 333-21011)
  
(B) 10-50Form of Director Indemnification Agreement (incorporated by reference to FE’s 10-Q filed May 7, 2009, Exhibit 10.1, File No. 333-21011)
  
(B) 10-51Form of Management Director Indemnification Agreement (incorporated by reference to FE’s 10-Q filed May 7, 2009, Exhibit 10.2, File No. 333-21011)
  
(B) 10-52Amended FirstEnergy Corp. Deferred Compensation Plan for Outside Directors, amended and restated as of September 21, 2010 (incorporated by reference to FE’s 10-Q filed October 26, 2010, Exhibit 10.1, File No. 333-21011)
(B) 10-53Amended FirstEnergy Corp. Executive Deferred Compensation Plan, amended and restated as of September 21, 2010 (incorporated by reference to FE’s 10-Q filed October 26, 2010, Exhibit 10.2, File No. 333-21011)
(B) 10-54FirstEnergy Corp. Change in Control Severence Plan (incorporated by reference to FE's Form 10-Q filed May 3, 2011, Exhibit 10.9, File No. 333-21011)
(B) 10-55Allegheny Energy, Inc. 1998 Long-Term Incentive Plan (incorporated by reference to FirstEnergy's Form 8-K filed February 25, 2011, Exhibit 10.2, File No. 21011)
(B) 10-56Allegheny Energy, Inc. 2008 Long-Term Incentive Plan (incorporated by reference to FirstEnergy's Form 8-K filed February 25, 2011, Exhibit 10.3, File No. 21011)
(B) 10-57Allegheny Energy, Inc. Non-Employee Director Stock Plan (incorporated by reference to FirstEnergy's Form 8-K filed February 25, 2011, Exhibit 10.4, File No. 21011)
(B) 10-58Allegheny Energy, Inc. Amended and Restated Revised Plan for Deferral of Compensation of directors (incorporated by reference to FirstEnergy's Form 8-K filed February 25, 2011, Exhibit 10.5, File No. 21011)
10-59Signal Peak Credit Agreement, including the forms of the guaranty and pledge agreement attached as exhibits thereto (incorporated by reference to FE’s 10-Q filed October 26, 2010, Exhibit 10.3, File No. 333-21011)
(A) 10-59(a)Amendment No. 1 to Signal Peak Credit Agreement, dated as of March 8, 2011.
(A) 10-59(b)Amendment No. 2 to Signal Peak Credit Agreement, dated as of September 26, 2011.


280



Exhibit
Number
10-60Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power Company, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein. (incorporated by reference to FE's Form 10-Q filed August 2, 2011, Exhibit 10.1, File No. 333-21011)
(A) 12-1Consolidated ratios of earnings to fixed charges.
  
(A) 21List of Subsidiaries of the Registrant at December 31, 2009.2011.
  
(A) 23-123Consent of Independent Registered Public Accounting Firm.
  
(A) 31-1Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
  
(A) 31-2Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
  
(A) 32Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. §1350.
  



260
(A) 95Mine Safety Disclosure
†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
(A)Provided herein in electronic format as an exhibit.
(B) 
(B)Management contract or compensatory plan contract or arrangement filed pursuant to Item 601 of Regulation S-K
S-K.
(C)Four substantially similar agreements, each dated as of the same date, were executed and delivered by the registrant and its affiliates with respect to four other series of pollution control revenue refunding bonds issued by the Ohio Water Development Authority, the Ohio Air Quality Authority and Beaver County Industrial Development Authority, Pennsylvania, relating to pollution control notes of FirstEnergy Nuclear Generation Corp.
(D)
Three substantially similar agreements, each dated as of the same date, were executed and delivered by the registrant and its affiliates with respect to three other series of pollution control revenue refunding bonds issued by the Ohio Water Development Authority and the Beaver County Industrial Development Authority relating to pollution control notes of FirstEnergy Generation Corp. and FirstEnergy Nuclear Generation Corp.

3. Exhibits – FES

3. Exhibits — FES
Exhibit
Number
3-1
Articles of Incorporation of FirstEnergy Solutions Corp., as amended August 31, 2001. (incorporated(incorporated by reference to FES’ Form S-4 filed August 6, 2007, Exhibit 3.1, File No. 333-145140-01) 333-145140-01)
  
3-2
Amended and Restated Code of Regulations of FirstEnergy Solutions Corp. effective as of August 26, 2009 (incorporated(incorporated by reference to FES’ Form 8-K filed August 7, 2009, Exhibit 3.4, File No. 000-53742)000-53742)
  
4-1
Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 19, 2008, of FirstEnergy Generation Corp. to The Bank of New York Trust Company, N.A., as Trustee (incorporated(incorporated by reference to FES’ 10-Q filed May 7, 2009, Exhibit 4.1, File No. 333-145140-01)
  
4-1(a)4-1
(a)
First Supplemental Indenture dated as of June 25, 2008 (including Form of First Mortgage Bonds, Guarantee Series A of 2008 due 2009 and Form First Mortgage Bonds, Guarantee Series B of 2008 due 2009). (incorporated(incorporated by reference to FES’ 10-Q filed May 7, 2009, Exhibit 4.1(a), File No. 333-145140-01)
  
4-1(b)4-1
(b)
Second Supplemental Indenture dated as of March 1, 2009 (including Form of First Mortgage Bonds, Guarantee Series A of 2009 due 2014 and Form of First Mortgage Bonds, Guarantee Series B of 2009 due 2023). (incorporated(incorporated by reference to FES’ 10-Q filed May 7, 2009, Exhibit 4.1(b), File No. 333-145140-01)
  
4-1(c)4-1
(c)
Third Supplemental Indenture dated as of March 31, 2009 (including Form of First Mortgage Bonds, Collateral Series A of 2009 due 2011). (incorporated(incorporated by reference to FES’ 10-Q filed May 7, 2009, Exhibit 4.1(c), File No. 333-145140-01)
  
4-1(d)4-1(d)Fourth Supplemental Indenture, dated as of June 1, 2009 (including Form of First Mortgage Bonds, Guarantee Series C of 2009 due 2018, Form of First Mortgage Bonds, Guarantee Series D of 2009 due 2029, Form of First Mortgage Bonds, Guarantee Series E of 2009 due 2029, Form of First Mortgage Bonds, Collateral Series B of 2009 due 2011 and Form of First Mortgage Bonds, Collateral Series C of 2009 due 2011). (incorporated by reference to FES’ Form 8-K filed June 19, 2009, Exhibit 4.3, File No. 333-145140-01)
  


281



4-1(e)
Exhibit
Number
4-1(e)Fifth Supplemental Indenture, dated as of June 30, 2009 (including Form of First Mortgage Bonds, Guarantee Series F of 2009 due 2047, Form of First Mortgage Bonds, Guarantee Series G of 2009 due 2018 and Form of First Mortgage Bonds, Guarantee Series H of 2009 due 2018). (incorporated by reference to FES’ Form 8-K filed July 6, 2009, Exhibit 4.2, File No. 333-145140-01)
  
4-1(f)4-1(f)Sixth Supplemental Indenture, dated as of December 1, 2009 (including Form of First Mortgage Bonds, Collateral Series D of 2009 due 2012 (incorporated by reference to FES’ Form 8-K filed December 4, 2009, Exhibit 4.2, File No. 000-53742)

261
4-2Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 1, 2009, by and between FirstEnergy Nuclear Generation Corp. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to FES’ Form 8-K filed June 19, 2009, Exhibit 4.1, File No. 333-145140-01)
  
4-2(a)4-2(a)First Supplemental Indenture, dated as of June 15, 2009 (including Form of First Mortgage Bonds, Guarantee Series A of 2009 due 2033, Form of First Mortgage Bonds, Guarantee Series B of 2009 due 2011, Form of First Mortgage Bonds, Collateral Series A of 2009 due 2010, Form of First Mortgage Bonds, Collateral Series B of 2009 due 2010, Form of First Mortgage Bonds, Collateral Series C of 2009 due 2010, Form of First Mortgage Bonds, Collateral Series D of 2009 due 2010, Form of First Mortgage Bonds, Collateral Series E of 2009 due 2010, Form of First Mortgage Bonds, Collateral Series F of 2009 due 2011 and Form of First Mortgage Bonds, Collateral Series G of 2009 due 2011). (incorporated by reference to FES’ Form 8-K filed June 19, 2009, Exhibit 4.2(i), File No. 333-145140-01)
  
4-2(b)4-2(b)Second Supplemental Indenture, dated as of June 30, 2009 (including Form of First Mortgage Bonds, Guarantee Series C of 2009 due 2033, Form of First Mortgage Bonds, Guarantee Series D of 2009 due 2033, Form of First Mortgage Bonds, Guarantee Series E of 2009 due 2033, Form of First Mortgage Bonds, Collateral Series H of 2009 due 2011, Form of First Mortgage Bonds, Collateral Series I of 2009 due 2011 and Form of First Mortgage Bonds, Collateral Series J of 2009 due 2010). (incorporated by reference to FES’ Form 8-K filed July 6, 2009, Exhibit 4.1(f), File No. 333-145140-01)
  
4-2(c)4-2(c)Third Supplemental Indenture, dated as of December 1, 2009 (including Form of First Mortgage Bonds, Collateral Series K of 2009 due 2012). (incorporated by reference to FES’ Form 8-K filed December 4, 2009, Exhibit 4.1, File No. 000-53742)
  
4-3Indenture, 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'FES’ Form 8-K filed August 7, 2009, Exhibit 4.1, File No. 000-53742)
  
4-3(a)4-3(a)First Supplemental Indenture, dated as of August 1, 2009 (including Form of 4.80% Senior Notes due 2015, Form of 6.05% Senior Notes due 2021 and Form of 6.80% Senior Notes due 2039). (incorporated by reference to FES'FES’ Form 8-K filed August 7, 2009, Exhibit 4.2, File No. 000-53742)
  
10-1
Form of 6.85% Exchange Certificate due 2034. (incorporated(incorporated by reference to FES’ Form S-4 filed August 6, 2007, Exhibit 4.1, File No. 333-145140-01)
  
10-2
Guaranty of FirstEnergy Solutions Corp., dated as of July 1, 2007. (incorporated(incorporated by reference to FE's FE’s Form 8-K/A filed August 2, 2007, Exhibit 10-9, File No. 333-21011)
  
10-3
Indenture of Trust, Open-End Mortgage and Security Agreement, dated as of July 1, 2007, between the applicable Lessor and The Bank of New York Trust Company, N.A., as Indenture Trustee. (incorporated(incorporated by reference to FE's FE’s Form 8-K/A filed August 2, 2007, Exhibit 10-3, File No. 333-21011)
  
10-4
6.85% Lessor Note due 2034. (incorporated(incorporated by reference to FE's FE’s Form 8-K/A filed August 2, 2007, Exhibit 10-3, File No. 333-21011)
  
10-5
Registration Rights Agreement, dated as of July 13, 2007, among FirstEnergy Generation Corp., FirstEnergy Solutions Corp., The Bank of New York Trust Company, N.A., as Pass Through Trustee, Morgan Stanley & Co. Incorporated, and Credit Suisse Securities (USA) LLC, as representatives of the several initial purchasers named in the Purchase Agreement. (incorporated by reference to FE's Form 8-K/A filed August 2, 2007, Exhibit 10-14, File No. 333-21011)

262
10-6
Participation Agreement, dated as of June 26, 2007, among FirstEnergy Generation Corp., as Lessee, FirstEnergy Solutions Corp., as Guarantor, the applicable Lessor, U.S. Bank Trust National Association, as Trust Company, the applicable Owner Participant, The Bank of New York Trust Company, N.A., as Indenture Trustee, and The Bank of New York Trust Company, N.A., as Pass Through Trustee. (incorporated(incorporated by reference to FE's FE’s Form 8-K/A filed August 2, 2007, Exhibit 10-1, File No. 333-21011)
  
10-7
Trust Agreement, dated as of June 26, 2007, between the applicable Owner Participant and U.S. Bank Trust National Association, as Owner Trustee. (incorporated(incorporated by reference to FE's FE’s Form 8-K/A filed August 2, 2007, Exhibit 10-2, File No. 333-21011)
  
10-8
Pass Through Trust Agreement, dated as of June 26, 2007, among FirstEnergy Generation Corp., FirstEnergy Solutions Corp., and The Bank of New York Trust Company, N.A., as Pass Through Trustee. (incorporated(incorporated by reference to FE's FE’s Form 8-K/A filed August 2, 2007, Exhibit 10-12, File No. 333-21011)
  
10-9
Bill of Sale and Transfer, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor. (incorporated(incorporated by reference to FE's FE’s Form 8-K/A filed August 2, 2007, Exhibit 10-5, File No. 333-21011)


282



Exhibit
Number
  
10-10
Facility Lease Agreement, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor. (incorporated(incorporated by reference to FE's FE’s Form 8-K/A filed August 2, 2007, Exhibit 10-6, File No. 333-21011)
  
10-11
Site Lease, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor. (incorporated(incorporated by reference to FE's FE’s Form 8-K/A filed August 2, 2007, Exhibit 10-7, File No. 333-21011)
  
10-12
Site Sublease, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor. (incorporated(incorporated by reference to FE's FE’s Form 8-K/A filed August 2, 2007, Exhibit 10-8, File No. 333-21011)
  
10-13
Support Agreement, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor. (incorporated(incorporated by reference to FE's FE’s Form 8-K/A filed August 2, 2007, Exhibit 10-10, File No. 333-21011)
  
10-14
Second Amendment to the Bruce Mansfield Units 1, 2, and 3 Operating Agreement, dated as of July 1, 2007, between FirstEnergy Generation Corp., The Cleveland Electric Illuminating Company and The Toledo Edison Company. (incorporated(incorporated by reference to FE's FE’s Form 8-K/A filed August 2, 2007, Exhibit 10-11, File No. 333-21011)
  
10-15OE Fossil Purchase and Sale Agreement by and between Ohio Edison Company (Seller) and FirstEnergy Generation Corp. (Purchaser). (incorporated by reference to FE’s Form 10-Q filed August 1, 2005, Exhibit 10.2, File No. 333-21011)
  
10-16CEI Fossil Purchase and Sale Agreement by and between The Cleveland Electric Illuminating Company (Seller) and FirstEnergy Generation Corp. (Purchaser). (incorporated by reference to FE’s Form 10-Q filed August 1, 2005, Exhibit 10.6, File No. 333-21011)
  
10-17TE Fossil Purchase and Sale Agreement by and between The Toledo Edison Company (Seller) and FirstEnergy Generation Corp. (Purchaser). (incorporated by reference to FE’s Form 10-Q filed August 1, 2005, Exhibit 10.2, File No. 333-21011)
  
10-18Agreement, dated August 26, 2005, by and between FirstEnergy Generation Corp. and Bechtel Power Corporation. (incorporated by reference to FE’s Form 10-Q filed November 2, 2005, Exhibit 10-2, File No. 333-21011)
  
10-19
CEI Fossil Note, dated October 24, 2005, of FirstEnergy Generation Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.15, File No. 333-145140-01)333-145140-01)
  
10-20
CEI Fossil Security Agreement, dated October 24, 2005, by and between FirstEnergy Generation Corp. and The Cleveland Electric Illuminating Company. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.16, File No. 333-145140-01)333-145140-01)

263
10-21
OE Fossil Note, dated October 24, 2005, of FirstEnergy Generation Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.17, File No. 333-145140-01)333-145140-01)
  
10-22
OE Fossil Security Agreement, dated October 24, 2005, by and between FirstEnergy Generation Corp. and Ohio Edison Company. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.18, File No. 333-145140-01)333-145140-01)
  
10-23
Amendment No. 1 to OE Fossil Security Agreement, dated as of June 30, 2007, between FirstEnergy Generation Corp. and Ohio Edison Company. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.19, File No. 333-145140-01)333-145140-01)
  
10-24
PP Fossil Note, dated October 24, 2005, of FirstEnergy Generation Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.20, File No. 333-145140-01)333-145140-01)
  
10-25
PP Fossil Security Agreement, dated October 24, 2005, by and between FirstEnergy Generation Corp. and Pennsylvania Power Company. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.21, File No. 333-145140-01)333-145140-01)
  
10-26
Amendment No. 1 to PP Fossil Security Agreement, dated as of June 30, 2007, between FirstEnergy Generation Corp. and Pennsylvania Power Company. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.22, File No. 333-145140-01)333-145140-01)
  
10-27
TE Fossil Note, dated October 24, 2005, of FirstEnergy Generation Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.23, File No. 333-145140-01)333-145140-01)
  
10-28
TE Fossil Security Agreement, dated October 24, 2005, by and between FirstEnergy Generation Corp. and The Toledo Edison Company. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.24, File No. 333-145140-01)333-145140-01)
  
10-29
CEI Nuclear Note, dated December 16, 2005, of FirstEnergy Nuclear Generation Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.25, File No. 333-145140-01)333-145140-01)


283



Exhibit
Number
  
10-30
CEI Nuclear Security Agreement, dated December 16, 2005, by and between FirstEnergy Nuclear Generation Corp. and The Cleveland Electric Illuminating Company. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.26, File No. 333-145140-01)333-145140-01)
  
10-31
OE Nuclear Note, dated December 16, 2005, of FirstEnergy Nuclear Generation Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.27,, File No. 333-145140-01)333-145140-01)
  
10-32
PP Nuclear Note, dated December 16, 2005, of FirstEnergy Nuclear Generation Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.28, File No. 333-145140-01)333-145140-01)
  
10-33
TE Nuclear Note, dated December 16, 2005, of FirstEnergy Nuclear Generation Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.29, File No. 333-145140-01)333-145140-01)
  
10-34
TE Nuclear Security Agreement, dated December 16, 2005, by and between FirstEnergy Nuclear Generation Corp. and The Toledo Edison Company. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.30, File No. 333-145140-01)333-145140-01)
  
10-35
Mansfield Power Supply Agreement, dated August 10, 2006, among The Cleveland Electric Illuminating Company, The Toledo Edison Company and FirstEnergy Generation Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.31, File No. 333-145140-01)333-145140-01)
  
10-36
Nuclear Power Supply Agreement, dated August 10, 2006, between FirstEnergy Nuclear Generation Corp. and FirstEnergy Solutions Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.32, File No. 333-145140-01)333-145140-01)

264
10-37
Revised Power Supply Agreement, dated December 8, 2006, among FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company and The Toledo Edison Company. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.34, File No. 333-145140-01)333-145140-01)
  
10-38
GENCO Power Supply Agreement, dated January 1, 2007, between FirstEnergy Generation Corp. and FirstEnergy Solutions Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.36, File No. 333-145140-01)333-145140-01)
 
  
10-39
Form of Guaranty dated as of March 2, 2007, between FirstEnergy Corp., as Guarantor, and Morgan Stanley Senior Funding, Inc., as Lender under the U.S. $250,000,000 Credit Agreement, dated as of March 2, 2007, with FirstEnergy Solutions Corp., as Borrower. (incorporated by reference to FE’s Form 10-Q filed May 9, 2007, Exhibit 10-23, File No. 333-145140-01)
 
10-40
Guaranty, dated as of March 26, 2007, by FirstEnergy Generation Corp. on behalf of FirstEnergy Solutions Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.39, File No. 333-145140-01)
333-145140-01)
  
10-4110-40
Guaranty, dated as of March 26, 2007, by FirstEnergy Solutions Corp. on behalf of FirstEnergy Generation Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.40, File No. 333-145140-01)333-145140-01)
  
10-4210-41
Guaranty, dated as of March 26, 2007, by FirstEnergy Solutions Corp. on behalf of FirstEnergy Nuclear Generation Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.41, File No. 333-145140-01)333-145140-01)
  
10-4310-42
Guaranty, dated as of March 26, 2007, by FirstEnergy Nuclear Generation Corp. on behalf of FirstEnergy Solutions Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.42, File No. 333-145140-01)333-145140-01)
  
(B) 10-4410-43
Form of Guaranty Agreement dated as of December 16, 2005 between FirstEnergy Corp. and FirstEnergy Solutions Corp. in Favor of Barclays Bank PLC as Administrative Agent for the Banks. (incorporated by reference to FE’s Form 10-K filed March 3, 2006, Exhibit 10-58, File No. 333-21011)
 
(B) 10-45
Form of Trust Indenture dated as of December 1, 2005 between Ohio Water Development Authority and JP Morgan Trust Company related to issuance of FirstEnergy Nuclear Generation Corp. pollution control revenue refunding bonds. (incorporated by reference to FE’s Form 10-K filed March 3, 2006, Exhibit 10-59,, File No. 333-21011)
333-21011)
  
10-4610-44
GENCO Power Supply Agreement dated as of October 14, 2005 between FirstEnergy Generation Corp. (Seller) and FirstEnergy Solutions Corp. (Buyer). (incorporated(incorporated by reference to FE’s Form 10-K filed March 3, 2006,, Exhibit 10-60, File No. 333-21011)
  
10-4710-45
Nuclear Power Supply Agreement dated as of October 14, 2005 between FirstEnergy Nuclear Generation Corp. (Seller) and FirstEnergy Solutions Corp. (Buyer). (incorporated by reference to FE’s Form 10-K filed March 3, 2006, Exhibit 10-61,, File No. 333-21011)333-21011)
  
(B) 10-4810-46
Form of Letter of Credit and Reimbursement Agreement Dated as of December 16, 2005 among FirstEnergy Nuclear Generation Corp., and the Participating Banks and Barclays Bank PLC. (incorporated by reference to FE’s Form 10-K filed March 3, 2006, Exhibit 10-62, File No. 333-21011)
 
(B) 10-49
Form of Waste Water Facilities and Solid Waste Facilities Loan Agreement between Ohio Water Development Authority and FirstEnergy Nuclear Generation Corp., dated as of December 1, 2005. (incorporated by reference to FE’s Form 10-K filed March 3, 2006, Exhibit 10-63,, File No. 333-21011)
333-21011)

265
10-50
10-47Nuclear Sale/Leaseback Power Supply Agreement dated as of October 14, 2005 between Ohio Edison Company and the Toledo Edison Company (Sellers) and FirstEnergy Nuclear Generation Corp. (Buyer). (incorporated by reference to FE’s Form 10-K filed March 3, 2006, Exhibit 10-64,, File No. 333-21011)333-21011)
  


284



10-51
Exhibit
Number
10-48Mansfield Power Supply Agreement dated as of October 14, 2005 between Cleveland Electric Illuminating Company and The Toledo Edison Company (Sellers) and FirstEnergy Generation Corp. (Buyer). (incorporated by reference to FE’s Form 10-K filed March 3, 2006, Exhibit 10-65,, File No. 333-21011)333-21011)
 
10-52
Power Supply Agreement dated as of October 31, 2005 between FirstEnergy Solutions Corp. (Seller) and the FirstEnergy Operating Companies – Ohio Edison Company, The Cleveland Electric Illuminating Company, and The Toledo Edison Company (Buyers). (incorporated by reference to FE’s Form 10-K filed March 3, 2006, Exhibit 10-66, File No. 333-21011)
10-53
Electric Power Supply Agreement dated as of October 3, 2005 between FirstEnergy Solutions Corp.  (Seller) and Pennsylvania Power Company (Buyer). (incorporated by reference to FE’s Form 10-K filed March 3, 2006, Exhibit 10-67, File No. 333-21011)
  
(C) 10-5410-49
Form of Letter of Credit and Reimbursement Agreement dated as of April 3, 2006 among FirstEnergy Generation Corp., the Participating Banks, Barclays Bank PLC, as administrative agent and fronting bank, and KeyBank National Association, as syndication agent. (incorporated by reference to FE’s Form 10-Q filed May 9, 2006, Exhibit 10-2, File No. 333-21011)
 
(C) 10-54(a)Form of Amendment No. 2 to Letter of Credit and Reimbursement Agreement, dated as of June 12, 2009, by and among FirstEnergy Generation Corp., FirstEnergy Corp. and FirstEnergy Solutions Corp., as guarantors, the banks party thereto, Barclays Bank PLC, as fronting Bank and administrative agent and KeyBank National Association, as syndication agent, to Letter of Credit and Reimbursement Agreement dated as of April 3, 2006 (incorporated by reference to FES’ Form 8-K filed June 19, 2009, Exhibit 10.2, File No. 333-145140-01)
(C) 10-55
Form of Trust Indenture dated as of April 1, 2006 between the Ohio Water Development Authority and The Bank of New York Trust Company, N.A. as Trustee securing pollution control revenue refunding bonds issued on behalf of FirstEnergy Generation Corp. (incorporated by reference to FE’s Form 10-Q filed May 9, 2006, Exhibit 10-3,, File No. 333-21011)
333-21011)
  
(C) 10-5610-50
Form of Waste Water Facilities Loan Agreement between the Ohio Water Development Authority and FirstEnergy Generation Corp. dated as of April 1, 2006. (incorporated by reference to FE’s Form 10-Q filed May 9, 2006, Exhibit 10-4,, File No. 333-21011)333-21011)
  
(D) 10-5710-51
Form of Trust Indenture dated as of December 1, 2006 between the Ohio Water Development Authority and The Bank of New York Trust Company, N.A. as Trustee securing State of Ohio Pollution Control Revenue Refunding Bonds (FirstEnergy Nuclear Generation Corp. Project). (incorporated by reference to FE’s Form 10-K filed February 28, 2007, Exhibit 10-77,, File No. 333-21011)333-21011)
  
(D) 10-5810-52
Form of Waste Water Facilities and Solid Waste Facilities Loan Agreement between the Ohio Water Development Authority and FirstEnergy Nuclear Generation Corp. dated as of December 1, 2006. (incorporated by reference to FE’s Form 10-K filed February 28, 2007, Exhibit 10-80,, File No. 333-21011)333-21011)
  
10-5910-53Consent Decree dated March 18, 2005. (incorporated by reference to FE’s Form 8-K filed March 18, 2005, Exhibit 10.1, File No. 333-21011)
  
10-6110-54
Amendment to Agreement for Engineering, Procurement and Construction of Air Quality Control Systems by and between FirstEnergy Generation Corp. and Bechtel Power Corporation dated September 14, 2007. (incorporated(incorporated by reference to FE’s Form 10-Q filed October 31, 2007, Exhibit 10.1,, File No. 333-21011)333-21011)
  
10-6110-55
Asset Purchase Agreement by and between Calpine Corporation, as Seller, and FirstEnergy Generation Corp., as Buyer, dated as of January 28, 2008. (incorporated(incorporated by reference to FE’s Form 10-K filed February 29, 2008, Exhibit 10-48,, File No. 333-21011)333-21011)

266
10-62
U.S. $300,000,000
10-56Credit Agreement, dated as of October 8, 2008, among FirstEnergy Generation Corp., as Borrower, FirstEnergy Corp. and FirstEnergy Solutions Corp., as Guarantors, Credit Suisse and the other Banks parties thereto from time to time, as Banks and Credit Suisse, as Administrative Agent. (incorporated by reference to FE’s Form 10-Q filed November 7, 2008, Exhibit 10.1, File No. 333-21011)
10-63
Master SSO Supply Agreement, entered into May 18, 2009, by and between The Cleveland Electric Illuminating Company, the Toledo Edison Company and Ohio Edison Company and FirstEnergy Solutions Corp. (incorporated by reference to FE’s Form 10-Q filed August 3, 2009, Exhibit 10.2, File No. 333-21011)
10-64Surplus Margin Guaranty, dated as of June 16, 2009, made by FirstEnergy Nuclear Generation Corp. in favor of The Cleveland Electric Illuminating Company, The Toledo Edison Company and Ohio Edison Company (incorporated by reference to FES’ Form 8-K filed June 19, 2009, Exhibit 10.3, File No. 333-145140-01)
10-65Registration Rights Agreement, dated August 7, 2009,17, 2011, among FirstEnergy Solutions Corp., and Morgan Stanley & Co. Incorporated, Barclays Capital Inc., Credit Suisse Securities (USA)Allegheny Energy Supply Company, LLC, and RBS Securities Inc.as borrowers, JPMorgan Chase Bank, N.A., as representatives ofadministrative agent, and the initial purchaserslending banks, fronting banks and swing line lenders identified therein. (incorporated by reference to FES'FE's Form 8-K10-Q filed August 7, 2009,2, 2011, Exhibit 10.1, File No. 000-53742)333-21011)
  
(A) 12-2Consolidated ratios of earnings to fixed charges.
  
(A) 31-1Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
  
(A) 31-2Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
  
(A) 32Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. §1350.
  
(A)Provided herein in electronic format as an exhibit.
  
(B)Four substantially similar agreements, each dated as of the same date, were executed and delivered by the registrant and its affiliates with respect to four other series of pollution control revenue refunding bonds issued by the Ohio Water Development Authority, the Ohio Air Quality Authority and Beaver County Industrial Development Authority, Pennsylvania, relating to pollution control notes of FirstEnergy Nuclear Generation Corp.
  
(C)Three substantially similar agreements, each dated as of the same date, were executed and delivered by the registrant and its affiliates with respect to three other series of pollution control revenue refunding bonds issued by the Ohio Water Development Authority and the Beaver County Industrial Development Authority relating to pollution control notes of FirstEnergy Generation Corp. and FirstEnergy Nuclear Generation Corp.
  
(D)Seven substantially similar agreements, each dated as of the same date, were executed and delivered by the registrant and its affiliates with respect to one other series of pollution control revenue refunding bonds issued by the Ohio Water Development Authority, three other series of pollution control bonds issued by the Ohio Air Quality Development Authority and the three other series of pollution control bonds issued by the Beaver County Industrial Development Authority, relating to pollution control notes of FirstEnergy Generation Corp. and FirstEnergy Nuclear Generation Corp.



3.    Exhibits – OE285


3. Exhibits — OE
Exhibit
Number
2-1Agreement and Plan of Merger, dated as of September 13, 1996, between Ohio Edison Company and Centerior Energy Corporation. (incorporated by reference to OE’s Form 8–8—K filed September 17, 1996, Exhibit 2–2—1, File No. 001-02578)

267
3-1
Amended and Restated Articles of Incorporation of Ohio Edison Company, Effective December 18, 2007. (incorporated(incorporated by reference to OE’s Form 10-K filed February 29, 2008, Exhibit 3-4,, File No. 001-02578)
  
3-2
Amended and Restated Code of Regulations of Ohio Edison Company, dated December 14, 2007. (incorporated(incorporated by reference to OE’s Form 10-K filed February 29, 2008, Exhibit 3-5,, File No. 001-02578)
4-1General Mortgage Indenture and Deed of Trust dated as of January 1, 1998 between Ohio Edison Company and the Bank of New York, as Trustee, as amended and supplemented by Supplemental Indentures: (incorporated by reference to OE’s Form S-3 filed June 5, 1996, Exhibit 4(b), File No. 333-05277)
  
4-1(a)4-1(a)February 1, 2003 (incorporated by reference to OE’s Form10-KForm 10-K filed March 15, 2004, Exhibit 4-4, File No. 001-02578)
4-1(b)
4-1(b)March 1, 2003 (incorporated by reference to OE’s Form10-KForm 10-K filed March 15, 2004, Exhibit 4-5,, File No. 001-02578)
4-1(c)
4-1(c)August 1, 2003 (incorporated by reference to OE’s Form10-KForm 10-K filed March 15, 2004, Exhibit 4-6, File No. 001-02578)
4-1(d)
June 1, 2004 (incorporated by reference to OE’s Form10-K filed March 10, 2005, Exhibit 4-4, File No. 001-02578)
4-1(e)4-1December(d)June 1, 2004 (incorporated by reference to OE’s Form10-KForm 10-K filed March 10, 2005, Exhibit 4-4, File No. 001-02578)
4-1(f)
4-1(e)December 1, 2004 (incorporated by reference to OE’s Form 10-K filed March 10, 2005, Exhibit 4-4, File No. 001-02578)
4-1(f)April 1, 2005 (incorporated by reference to OE’s Form 10-Q filed August 1, 2005, Exhibit 4-4,, File No. 001-02578)
4-1(g)
4-1(g)April 15, 2005 (incorporated by reference to OE’s Form 10-Q filed August 1, 2005, Exhibit 4-5,, File No. 001-02578)
4-1(h)
4-1(h)June 1, 2005 (incorporated by reference to OE’s Form 10-Q filed August 1, 2005, Exhibit 4-6,, File No. 001-02578)
4-1(i)
4-1(i)October 1, 2008 (incorporated by reference to OE’s Form 8-K filed October 22, 2008, Exhibit 4.1,, File No. 001-02578)
  
4-2
Indenture dated as of April 1, 2003 between Ohio Edison Company and The Bank of New York, as Trustee. (incorporated by reference to OE’s Form10-KForm 10-K filed March 15, 2004, Exhibit 4-3,, File No. 001-02578)
  
4-2(a)4-2(a)Officer’s Certificate (including the forms of the 6.40% Senior Notes due 2016 and the 6.875% Senior Notes due 2036), dated June 21, 2006. (incorporated by reference to OE’s Form 8-K filed June 27, 2006, Exhibit 4, File No. 001-02578)
  
10-1Amendment No. 4 dated as of July 1, 1985 to the Bond Guaranty dated as of October 1, 1973, as amended, by the CAPCO Companies to National City Bank as Bond Trustee. (incorporated by reference to 1985 Form 10-K, Exhibit 10-30)
  
10-2Amendment No. 5 dated as of May 1, 1986, to the Bond Guaranty by the CAPCO Companies to National City Bank as Bond Trustee. (incorporated by reference to 1986 Form 10-K, Exhibit 10-33)
  
10-3Amendment No. 6A dated as of December 1, 1991, to the Bond Guaranty dated as of October 1, 1973, by The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company to National City Bank, as Bond Trustee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-33)
  
10-4Amendment No. 6B dated as of December 30, 1991, to the Bond Guaranty dated as of October 1, 1973 by The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company to National City Bank, as Bond Trustee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-34)
  
(B) 10-5Ohio Edison System Executive Supplemental Life Insurance Plan. (incorporated by reference to OE’s Form 10-K filed March 19, 1996, Exhibit 10-44, File No. 001-02578)

268
(B) 10-6Ohio Edison System Executive Incentive Compensation Plan. (incorporated by reference to OE’s Form 10-K filed March 19, 1996, Exhibit 10-45, File No. 001-02578)
  
(B) 10-7Ohio Edison System Restated and Amended Supplemental Executive Retirement Plan. (incorporated by reference to OE’s Form 10-K filed March 19, 1996, Exhibit 10-47, File No. 001-02578)
  
(B) 10-8Form of Amendment, effective November 7, 2001, to GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries, Deferred Remuneration Plan for Outside Directors of GPU, Inc., and Retirement Plan for Outside Directors of GPU, Inc. (incorporated by reference to OE’s Form 10-K filed April 1, 2002, Exhibit 10-26, File No. 001-02578)


286



Exhibit
Number
  
(B) 10-9GPU, Inc. Stock Option and Restricted Stock Plan for MYR Group, Inc. Employees. (incorporated by reference to OE’s Form 10-K filed April 1, 2002, Exhibit 10-27, File No. 001-02578))
  
(B) 10-10Severance pay agreement between Ohio Edison Company and A. J. Alexander. (incorporated by reference to OE’s Form 10-K filed March 19, 1996, Exhibit 10-50, File No. 001-02578)
  
(C) 10-11Participation Agreement dated as of March 16, 1987 among Perry One Alpha Limited Partnership, as Owner Participant, the Original Loan Participants listed in Schedule 1 Hereto, as Original Loan Participants, PNPP Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to 1986 Form 10-K, Exhibit 28-1)
  
(C) 10-12Amendment No. 1 dated as of September 1, 1987 to Participation Agreement dated as of March 16, 1987 among Perry One Alpha Limited Partnership, as Owner Participant, the Original Loan Participants listed in Schedule 1 thereto, as Original Loan Participants, PNPP Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company (now The Bank of New York), as Indenture Trustee, and Ohio Edison Company, as Lessee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-46)
  
(C) 10-13Amendment No. 3 dated as of May 16, 1988 to Participation Agreement dated as of March 16, 1987, as amended among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and Ohio Edison Company, as Lessee. (incorporated by reference to 1992 Form 10-K, Exhibit 10-47)
  
(C) 10-14Amendment No. 4 dated as of November 1, 1991 to Participation Agreement dated as of March 16, 1987 among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-47)
  
(C) 10-15Amendment No. 5 dated as of November 24, 1992 to Participation Agreement dated as of March 16, 1987, as amended, among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company as Lessee. (incorporated by reference to 1992 Form 10-K, Exhibit 10-49)
  
(C) 10-16Amendment No. 6 dated as of January 12, 1993 to Participation Agreement dated as of March 16, 1987 among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to 1992 Form 10-K, Exhibit 10-50)

269
(C) 10-17Amendment No. 7 dated as of October 12, 1994 to Participation Agreement dated as of March 16, 1987 as amended, among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-54, File No. 001-02578))
  
(C) 10-18Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee, with Perry One Alpha Limited Partnership, Lessor, and Ohio Edison Company, Lessee. (incorporated by reference to 1986 Form 10-K, Exhibit 28-2)
  
(C) 10-19Amendment No. 1 dated as of September 1, 1987 to Facility Lease dated as of March 16, 1997 between The First National Bank of Boston, as Owner Trustee, Lessor and Ohio Edison Company, Lessee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-49)
  
(C) 10-20Amendment No. 2 dated as of November 1, 1991, to Facility Lease dated as of March 16, 1987, between The First National Bank of Boston, as Owner Trustee, Lessor and Ohio Edison Company, Lessee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-50)
  
(C) 10-21Amendment No. 3 dated as of November 24, 1992 to Facility Lease dated as March 16, 1987 as amended, between The First National Bank of Boston, as Owner Trustee, with Perry One Alpha Limited partnership, as Owner Participant and Ohio Edison Company, as Lessee. (incorporated by reference to 1992 Form 10-K, Exhibit 10-54)
  
(C) 10-22Amendment No. 4 dated as of January 12, 1993 to Facility Lease dated as of March 16, 1987 as amended, between, The First National Bank of Boston, as Owner Trustee, with Perry One Alpha Limited Partnership, as Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-59, File No. 001-02578))
  


287



Exhibit
Number
(C) 10-23Amendment No. 5 dated as of October 12, 1994 to Facility Lease dated as of March 16, 1987 as amended, between, The First National Bank of Boston, as Owner Trustee, with Perry One Alpha Limited Partnership, as Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-60, File No. 001-02578)
  
(C) 10-24Letter Agreement dated as of March 19, 1987 between Ohio Edison Company, Lessee, and The First National Bank of Boston, Owner Trustee under a Trust dated March 16, 1987 with Chase Manhattan Realty Leasing Corporation, required by Section 3(d) of the Facility Lease. (incorporated by reference to 1986 Form 10-K, Exhibit 28-3)
  
(C) 10-25Ground Lease dated as of March 16, 1987 between Ohio Edison Company, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with the Owner Participant, Tenant. (incorporated by reference to 1986 Form 10-K, Exhibit 28-4)
  
(C) 10-26Trust Agreement dated as of March 16, 1987 between Perry One Alpha Limited Partnership, as Owner Participant, and The First National Bank of Boston. (incorporated by reference to 1986 Form 10-K, Exhibit 28-5)
  
(C) 10-27Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of March 16, 1987 with Perry One Alpha Limited Partnership, and Irving Trust Company, as Indenture Trustee. (incorporated by reference to 1986 Form 10-K, Exhibit 28-6)
  
(C) 10-28Supplemental Indenture No. 1 dated as of September 1, 1987 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston as Owner Trustee and Irving Trust Company (now The Bank of New York), as Indenture Trustee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-55)
  
(C) 10-29Supplemental Indenture No. 2 dated as of November 1, 1991 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee and The Bank of New York, as Indenture Trustee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-56)

270
(C) 10-30Tax Indemnification Agreement dated as of March 16, 1987 between Perry One, Inc. and PARock Limited Partnership as General Partners and Ohio Edison Company, as Lessee. (incorporated by reference to 1986 Form 10-K, Exhibit 28-7)
  
(C) 10-31Amendment No. 1 dated as of November 1, 1991 to Tax Indemnification Agreement dated as of March 16, 1987 between Perry One, Inc. and PARock Limited Partnership and Ohio Edison Company. (incorporated by reference to 1991 Form 10-K, Exhibit 10-58)
  
(C) 10-32Amendment No. 2 dated as of January 12, 1993 to Tax Indemnification Agreement dated as of March 16, 1987 between Perry One, Inc. and PARock Limited Partnership and Ohio Edison Company. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-69, File No. 001-02578)
  
(C) 10-33Amendment No. 3 dated as of October 12, 1994 to Tax Indemnification Agreement dated as of March 16, 1987 between Perry One, Inc. and PARock Limited Partnership and Ohio Edison Company. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-70, File No. 001-02578)
  
(C) 10-34Partial Mortgage Release dated as of March 19, 1987 under the Indenture between Ohio Edison Company and Bankers Trust Company, as Trustee, dated as of the 1st day of August 1930. (incorporated by reference to 1986 Form 10-K, Exhibit 28-8)
  
(C) 10-35Assignment, Assumption and Further Agreement dated as of March 16, 1987 among The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership, The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company and Toledo Edison Company. (incorporated by reference to 1986 Form 10-K, Exhibit 28-9)
  
(C) 10-36Additional Support Agreement dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership, and Ohio Edison Company. (incorporated by reference to 1986 Form 10-K, Exhibit 28-10)
  
(C) 10-37Bill of Sale, Instrument of Transfer and Severance Agreement dated as of March 19, 1987 between Ohio Edison Company, Seller, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership. (incorporated by reference to 1986 Form 10-K, Exhibit 28-11)
  
(C) 10-38Easement dated as of March 16, 1987 from Ohio Edison Company, Grantor, to The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership, Grantee. (incorporated by reference to 1986 Form 10-K, Exhibit 28-12)
  


288



Exhibit
Number
10-39Participation Agreement dated as of March 16, 1987 among Security Pacific Capital Leasing Corporation, as Owner Participant, the Original Loan Participants listed in Schedule 1 Hereto, as Original Loan Participants, PNPP Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to 1986 Form 10-K, Exhibit 28-13)
  
10-40Amendment No. 1 dated as of September 1, 1987 to Participation Agreement dated as of March 16, 1987 among Security Pacific Capital Leasing Corporation, as Owner Participant, The Original Loan Participants Listed in Schedule 1 thereto, as Original Loan Participants, PNPP Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-65)

271
10-41Amendment No. 4 dated as of November 1, 1991, to Participation Agreement dated as of March 16, 1987 among Security Pacific Capital Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-66)
  
10-42Amendment No. 5 dated as of November 24, 1992 to Participation Agreement dated as of March 16, 1987 as amended among Security Pacific Capital Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to 1992 Form 10-K, Exhibit 10-71)
  
10-43Amendment No. 6 dated as of January 12, 1993 to Participation Agreement dated as of March 16, 1987 as amended among Security Pacific Capital Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-80, File No. 001-02578)
  
10-44Amendment No. 7 dated as of October 12, 1994 to Participation Agreement dated as of March 16, 1987 as amended among Security Pacific Capital Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, File No. 001-02578)
  
10-45Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee, with Security Pacific Capital Leasing Corporation, Lessor, and Ohio Edison Company, as Lessee. (incorporated by reference to 1986 Form 10-K, Exhibit 28-14)
  
10-46Amendment No. 1 dated as of September 1, 1987 to Facility Lease dated as of March 16, 1987 between The First National Bank of Boston as Owner Trustee, Lessor and Ohio Edison Company, Lessee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-68)
  
10-47Amendment No. 2 dated as of November 1, 1991 to Facility Lease dated as of March 16, 1987 between The First National Bank of Boston as Owner Trustee, Lessor and Ohio Edison Company, Lessee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-69)
  
10-48Amendment No. 3 dated as of November 24, 1992 to Facility Lease dated as of March 16, 1987, as amended, between, The First National Bank of Boston, as Owner Trustee, with Security Pacific Capital Leasing Corporation, as Owner Participant and Ohio Edison Company, as Lessee. (incorporated by reference to 1992 Form 10-K, Exhibit 10-75)
  
10-49Amendment No. 4 dated as of January 12, 1993 to Facility Lease dated as of March 16, 1987 as amended between, The First National Bank of Boston, as Owner Trustee, with Security Pacific Capital Leasing Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by reference to 1992 Form 10-K, Exhibit 10-76)
  
10-50Amendment No. 5 dated as of October 12, 1994 to Facility Lease dated as of March 16, 1987 as amended between, The First National Bank of Boston, as Owner Trustee, with Security Pacific Capital Leasing Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-87, File No. 001-02578)
  
10-51Letter Agreement dated as of March 19, 1987 between Ohio Edison Company, as Lessee, and The First National Bank of Boston, as Owner Trustee under a Trust, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, required by Section 3(d) of the Facility Lease. (incorporated by reference to 1986 Form 10-K, Exhibit 28-15)

272
10-52Ground Lease dated as of March 16, 1987 between Ohio Edison Company, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership, Tenant. (incorporated by reference to 1986 Form 10-K, Exhibit 28-16)
  
10-53Trust Agreement dated as of March 16, 1987 between Security Pacific Capital Leasing Corporation, as Owner Participant, and The First National Bank of Boston. (incorporated by reference to 1986 Form 10-K, Exhibit 28-17)


289



Exhibit
Number
  
10-54Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, and Irving Trust Company, as Indenture Trustee. (incorporated by reference to 1986 Form 10-K, Exhibit 28-18)
  
10-55Supplemental Indenture No. 1 dated as of September 1, 1987 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee and Irving Trust Company (now The Bank of New York), as Indenture Trustee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-74)
  
10-56Supplemental Indenture No. 2 dated as of November 1, 1991 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee and The Bank of New York, as Indenture Trustee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-75)
  
10-57Tax Indemnification Agreement dated as of March 16, 1987 between Security Pacific Capital Leasing Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by reference to 1986 Form 10-K, Exhibit 28-19)
  
10-58Amendment No. 1 dated as of November 1, 1991 to Tax Indemnification Agreement dated as of March 16, 1987 between Security Pacific Capital Leasing Corporation and Ohio Edison Company. (incorporated by reference to 1991 Form 10-K, Exhibit 10-77)
  
10-59Amendment No. 2 dated as of January 12, 1993 to Tax Indemnification Agreement dated as of March 16, 1987 between Security Pacific Capital Leasing Corporation and Ohio Edison Company. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-96, File No. 001-02578)
  
10-60Amendment No. 3 dated as of October 12, 1994 to Tax Indemnification Agreement dated as of March 16, 1987 between Security Pacific Capital Leasing Corporation and Ohio Edison Company. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-97, File No. 001-02578)
  
10-61Assignment, Assumption and Further Agreement dated as of March 16, 1987 among The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company and Toledo Edison Company. (incorporated by reference to 1986 Form 10-K, Exhibit 28-20)
  
10-62Additional Support Agreement dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, and Ohio Edison Company. (incorporated by reference to 1986 Form 10-K, Exhibit 28-21)
  
10-63Bill of Sale, Instrument of Transfer and Severance Agreement dated as of March 19, 1987 between Ohio Edison Company, Seller, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, Buyer. (incorporated by reference to 1986 Form 10-K, Exhibit 28-22)
  
10-64Easement dated as of March 16, 1987 from Ohio Edison Company, Grantor, to The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, Grantee. (incorporated by reference to 1986 Form 10-K, Exhibit 28-23)

273
10-65Refinancing Agreement dated as of November 1, 1991 among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee, The Bank of New York, as Collateral Trust Trustee, The Bank of New York, as New Collateral Trust Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-82)
  
10-66Refinancing Agreement dated as of November 1, 1991 among Security Pacific Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee, The Bank of New York, as Collateral Trust Trustee, The Bank of New York as New Collateral Trust Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-83)
  
10-67Ohio Edison Company Master Decommissioning Trust Agreement for Perry Nuclear Power Plant Unit One, Perry Nuclear Power Plant Unit Two, Beaver Valley Power Station Unit One and Beaver Valley Power Station Unit Two dated July 1, 1993. (1993 Form 10-K, Exhibit 10-94)
  
(D) 10-68Participation Agreement dated as of September 15, 1987, among Beaver Valley Two Pi Limited Partnership, as Owner Participant, the Original Loan Participants listed in Schedule 1 Thereto, as Original Loan Participants, BVPS Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company as Lessee. (incorporated by reference to 1987 Form 10-K, Exhibit 28-1)
  


290



Exhibit
Number
(D) 10-69Amendment No. 1 dated as of February 1, 1988, to Participation Agreement dated as of September 15, 1987, among Beaver Valley Two Pi Limited Partnership, as Owner Participant, the Original Loan Participants listed in Schedule 1 Thereto, as Original Loan Participants, BVPS Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to 1987 Form 10-K, Exhibit 28-2)
  
(D) 10-70Amendment No. 3 dated as of March 16, 1988 to Participation Agreement dated as of September 15, 1987, as amended, among Beaver Valley Two Pi Limited Partnership, as Owner Participant, BVPS Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to 1992 Form 10-K, Exhibit 10-99)
  
(D) 10-71Amendment No. 4 dated as of November 5, 1992 to Participation Agreement dated as of September 15, 1987, as amended, among Beaver Valley Two Pi Limited Partnership, as Owner Participant, BVPS Funding Corporation, BVPS II Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to 1992 Form 10-K, Exhibit 10-100)
  
(D) 10-72Amendment No. 5 dated as of September 30, 1994 to Participation Agreement dated as of September 15, 1987, as amended, among Beaver Valley Two Pi Limited Partnership, as Owner Participant, BVPS Funding Corporation, BVPS II Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-118, File No. 001-02578)
  
(D) 10-73Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee, with Beaver Valley Two Pi Limited Partnership, Lessor, and Ohio Edison Company, Lessee. (incorporated by reference to 1987 Form 10-K, Exhibit 28-3)
  
(D) 10-74Amendment No. 1 dated as of February 1, 1988, to Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee, with Beaver Valley Two Pi Limited Partnership, Lessor, and Ohio Edison Company, Lessee. (incorporated by reference to 1987 Form 10-K, Exhibit 28-4)

274
(D) 10-75Amendment No. 2 dated as of November 5, 1992, to Facility Lease dated as of September 15, 1987, as amended, between The First National Bank of Boston, as Owner Trustee, with Beaver Valley Two Pi Limited Partnership, as Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by reference to 1992 Form 10-K, Exhibit 10-103)
  
(D) 10-76Amendment No. 3 dated as of September 30, 1994 to Facility Lease dated as of September 15, 1987, as amended, between The First National Bank of Boston, as Owner Trustee, with Beaver Valley Two Pi Limited Partnership, as Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-122, File No. 001-02578)
  
(D) 10-77Ground Lease and Easement Agreement dated as of September 15, 1987, between Ohio Edison Company, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Beaver Valley Two Pi Limited Partnership, Tenant. (incorporated by reference to 1987 Form 10-K, Exhibit 28-5)
  
(D) 10-78Trust Agreement dated as of September 15, 1987, between Beaver Valley Two Pi Limited Partnership, as Owner Participant, and The First National Bank of Boston. (incorporated by reference to 1987 Form 10-K, Exhibit 28-6)
  
(D) 10-79Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987, with Beaver Valley Two Pi Limited Partnership, and Irving Trust Company, as Indenture Trustee. (incorporated by reference to 1987 Form 10-K, Exhibit 28-7)
  
(D) 10-80Supplemental Indenture No. 1 dated as of February 1, 1988 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with Beaver Valley Two Pi Limited Partnership and Irving Trust Company, as Indenture Trustee. (incorporated by reference to 1987 Form 10-K, Exhibit 28-8)
  
(D) 10-81Tax Indemnification Agreement dated as of September 15, 1987, between Beaver Valley Two Pi Inc. and PARock Limited Partnership as General Partners and Ohio Edison Company, as Lessee. (incorporated by reference to 1987 Form 10-K, Exhibit 28-9)
  
(D) 10-82Amendment No. 1 dated as of November 5, 1992 to Tax Indemnification Agreement dated as of September 15, 1987, between Beaver Valley Two Pi Inc. and PARock Limited Partnership as General Partners and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-128, File No. 001-02578)
  
(D) 10-83Amendment No. 2 dated as of September 30, 1994 to Tax Indemnification Agreement dated as of September 15, 1987, between Beaver Valley Two Pi Inc. and PARock Limited Partnership as General Partners and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-129, File No. 001-02578)
  
(D) 10-84Tax Indemnification Agreement dated as of September 15, 1987, between HG Power Plant, Inc., as Limited Partner and Ohio Edison Company, as Lessee. (1987 Form 10-K, Exhibit 28-10)


291



Exhibit
Number
  
(D) 10-85Amendment No. 1 dated as of November 5, 1992 to Tax Indemnification Agreement dated as of September 15, 1987, between HG Power Plant, Inc., as Limited Partner and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-131, File No. 001-02578)
  
(D) 10-86Amendment No. 2 dated as of September 30, 1994 to Tax Indemnification Agreement dated as of September 15, 1987, between HG Power Plant, Inc., as Limited Partner and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-132, File No. 001-02578)

275
(D) 10-87Assignment, Assumption and Further Agreement dated as of September 15, 1987, among The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Beaver Valley Two Pi Limited Partnership, The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company and Toledo Edison Company. (incorporated by reference to 1987 Form 10-K, Exhibit 28-11)
  
(D) 10-88Additional Support Agreement dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Beaver Valley Two Pi Limited Partnership, and Ohio Edison Company. (incorporated by reference to 1987 Form 10-K, Exhibit 28-12)
  
(E) 10-89Participation Agreement dated as of September 15, 1987, among Chrysler Consortium Corporation, as Owner Participant, the Original Loan Participants listed in Schedule 1 Thereto, as Original Loan Participants, BVPS Funding Corporation as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to 1987 Form 10-K, Exhibit 28-13)
  
(E) 10-90Amendment No. 1 dated as of February 1, 1988, to Participation Agreement dated as of September 15, 1987, among Chrysler Consortium Corporation, as Owner Participant, the Original Loan Participants listed in Schedule 1 Thereto, as Original Loan Participants, BVPS Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and Ohio Edison Company, as Lessee. (incorporated by reference to 1987 Form 10-K, Exhibit 28-14)
  
(E) 10-91Amendment No. 3 dated as of March 16, 1988 to Participation Agreement dated as of September 15, 1987, as amended, among Chrysler Consortium Corporation, as Owner Participant, BVPS Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and Ohio Edison Company, as Lessee. (incorporated by reference to 1992 Form 10-K, Exhibit 10-114)
  
(E) 10-92Amendment No. 4 dated as of November 5, 1992 to Participation Agreement dated as of September 15, 1987, as amended, among Chrysler Consortium Corporation, as Owner Participant, BVPS Funding Corporation, BVPS II Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to 1992 Form 10-K, Exhibit 10-115)
  
(E) 10-93Amendment No. 5 dated as of January 12, 1993 to Participation Agreement dated as of September 15, 1987, as amended, among Chrysler Consortium Corporation, as Owner Participant, BVPS Funding Corporation, BVPS II Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-139, File No. 001-02578)
  
(E) 10-94
10-94		Amendment No. 6 dated as of September 30, 1994 to Participation Agreement dated as of September 15, 1987, as amended, among Chrysler Consortium Corporation, as Owner Participant, BVPS Funding Corporation, BVPS II Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-140, File No. 001-02578)
  
(E) 10-95Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee, with Chrysler Consortium Corporation, Lessor, and Ohio Edison Company, as Lessee. (incorporated by reference to 1987 Form 10-K, Exhibit 28-15)
  
(E) 10-96Amendment No. 1 dated as of February 1, 1988, to Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee, with Chrysler Consortium Corporation, Lessor, and Ohio Edison Company, Lessee. (incorporated by reference to 1987 Form 10-K, Exhibit 28-16)

276
(E) 10-97Amendment No. 2 dated as of November 5, 1992 to Facility Lease dated as of September 15, 1987, as amended, between The First National Bank of Boston, as Owner Trustee, with Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by reference to 1992 Form 10-K, Exhibit 10-118)
  
(E) 10-98Amendment No. 3 dated as of January 12, 1993 to Facility Lease dated as of September 15, 1987, as amended, between The First National Bank of Boston, as Owner Trustee, with Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by reference to 1992 Form 10-K, Exhibit 10-119)
  


292



Exhibit
Number
(E) 10-99Amendment No. 4 dated as of September 30, 1994 to Facility Lease dated as of September 15, 1987, as amended, between The First National Bank of Boston, as Owner Trustee, with Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-145, File No. 001-02578)
  
(E) 10-100Ground Lease and Easement Agreement dated as of September 15, 1987, between Ohio Edison Company, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Chrysler Consortium Corporation, Tenant. (incorporated by reference to 1987 Form 10-K, Exhibit 28-17)
  
(E) 10-101Trust Agreement dated as of September 15, 1987, between Chrysler Consortium Corporation, as Owner Participant, and The First National Bank of Boston. (incorporated by reference to 1987 Form 10-K, Exhibit 28-18)
  
(E) 10-102Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Chrysler Consortium Corporation and Irving Trust Company, as Indenture Trustee. (incorporated by reference to 1987 Form 10-K, Exhibit 28-19)
  
(E) 10-103Supplemental Indenture No. 1 dated as of February 1, 1988 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with Chrysler Consortium Corporation and Irving Trust Company, as Indenture Trustee. (incorporated by reference to 1987 Form 10-K, Exhibit 28-20)
  
(E) 10-104Tax Indemnification Agreement dated as of September 15, 1987, between Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, Lessee. (incorporated by reference to 1987 Form 10-K, Exhibit 28-21)
  
(E) 10-105Amendment No. 1 dated as of November 5, 1992 to Tax Indemnification Agreement dated as of September 15, 1987, between Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-151, File No. 001-02578)
  
(E) 10-106Amendment No. 2 dated as of January 12, 1993 to Tax Indemnification Agreement dated as of September 15, 1987, between Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-152, File No. 001-02578)
  
(E) 10-107Amendment No. 3 dated as of September 30, 1994 to Tax Indemnification Agreement dated as of September 15, 1987, between Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-153, File No. 001-02578)
  
(E) 10-108Assignment, Assumption and Further Agreement dated as of September 15, 1987, among The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Chrysler Consortium Corporation, The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company, and Toledo Edison Company. (incorporated by reference to 1987 Form 10-K, Exhibit 28-22)

277
(E) 10-109Additional Support Agreement dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Chrysler Consortium Corporation, and Ohio Edison Company. (incorporated by reference to 1987 Form 10-K, Exhibit 28-23)
  
10-110Operating Agreement for Bruce Mansfield Units Nos. 1, 2 and 3 dated as of June 1, 1976, and executed on September 15, 1987, by and between the CAPCO Companies. (incorporated by reference to 1987 Form 10-K, Exhibit 28-25)
  
10-111OE Nuclear Capital Contribution Agreement by and between Ohio Edison Company and FirstEnergy Nuclear Generation Corp. (incorporated by reference to OE’s Form 10-Q filed August 1, 2005, Exhibit 10.1, File No. 001-02578)
  
10-112OE Fossil Purchase and Sale Agreement by and between Ohio Edison Company (Seller) and FirstEnergy Generation Corp. (Purchaser). (incorporated by reference to OE’s Form 10-Q filed August 1, 2005, Exhibit 10.2, File No. 001-02578)
  
10-113
OE Fossil Security Agreement, dated October 24, 2005, by and between FirstEnergy Generation Corp. and Ohio Edison Company. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.18, File No. 333-145140-01) 333-145140-01)
  
10-114Consent Decree dated March 18, 2005. (incorporated by reference to FE’s Form 8-K filed March 18, 2005, Exhibit 10.1, File No. 333-21011)
  
10-115Nuclear Sale/Leaseback Power Supply Agreement dated as of October 14, 2005 between Ohio Edison Company and The Toledo Edison Company (Sellers) and FirstEnergy Nuclear Generation Corp. (Buyer). (incorporated by reference to OE’s Form 10-K filed March 2, 2006, Exhibit 10-64, File No. 001-02578)
  


293



Exhibit
Number
10-116Power SupplyCredit Agreement, dated as of October 31, 2005 betweenJune 17, 2011, among FirstEnergy Solutions Corp. (Seller) and the FirstEnergy Operating Companies – Ohio Edison Company,, The Cleveland Electric Illuminating Company, andMetropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, (Buyers).American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power Company, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein. (incorporated by reference to OE’s Form 10-K filed March 2, 2006, Exhibit 10-65, File No. 001-02578)
10-117
Revised Power Supply Agreement, dated December 8, 2006, among FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company and The Toledo Edison Company. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.34, File No. 333-145140-01)
10-118Master SSO Supply Agreement, entered into May 18, 2009, by and between The Cleveland Electric Illuminating Company, the Toledo Edison Company and Ohio Edison Company and FirstEnergy Solutions Corp. (incorporated by reference to OE’sFE's Form 10-Q filed August 3, 2009,2, 2011, Exhibit 10.2,10.1, File No. 001-02578)333-21011)
  
(A) 12-3Consolidated ratios of earnings to fixed charges.
  
(A) 23-2Consent of Independent Registered Public Accounting Firm.
 
(A) 31-1Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
  
(A) 31-2Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
  
(A) 32Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. §1350.
  
(A)Provided herein in electronic format as an exhibit.
  
(B)Management contract or compensatory plan contract or arrangement filed pursuant to Item 601 of Regulation S-K.

278
(C)Substantially similar documents have been entered into relating to three additional Owner Participants.
  
(D)Substantially similar documents have been entered into relating to five additional Owner Participants.
  
(E)Substantially similar documents have been entered into relating to two additional Owner Participants.

3.      Exhibits – Common Exhibits for CEI and TE

Exhibit
Number

3. Exhibits — Common Exhibits for CEI and TE
Exhibit
Number
2-1Agreement and Plan of Merger between Ohio Edison Company and Centerior Energy dated as of September 13, 1996. (incorporated by reference to FE’s Form S-4 filed February 3, 1997, Exhibit (2)-1, File No. 333-21011)
  
2-2
Merger Agreement by and among Centerior Acquisition Corp., FirstEnergy Corp and Centerior Energy Corp.Corp. (incorporated by reference to FE’s Form S-4 filed February 3, 1997, Exhibit (2)-3, File No. 333-21011)
  
10-1CAPCO Administration Agreement dated November 1, 1971, as of September 14, 1967, among the CAPCO Group members regarding the organization and procedures for implementing the objectives of the CAPCO Group. (incorporated by reference to Amendment No. 1, Exhibit 5(p), File No. 2-42230)
  
10-2Amendment No. 1, dated January 4, 1974, to CAPCO Administration Agreement among the CAPCO Group members. (incorporated by reference to OE’s File No. 2-68906, Exhibit 5(c)(3))
  
10-3Agreement for the Termination or Construction of Certain Agreement By and Among the CAPCO Group members, dated December 23, 1993 and effective as of September 1, 1980. (incorporated by reference to CEI’s Form 10-K filed on March 31, 1994, Exhibit 10b(4), File No. 001-02323)
  
10-4
Second Amendment to the Bruce Mansfield Units 1, 2, and 3 Operating Agreement, dated as of July 1, 2007, between FirstEnergy Generation Corp., The Cleveland Electric Illuminating Company and The Toledo Edison Company. (incorporated by reference to FE’s Form 8-K/A filed August 2, 2007, Exhibit 10-11, File. No. 333-21011)333-21011)
  
10-5Amendment No. 6A dated as of December 1, 1991, to the Bond Guaranty dated as of October 1, 1973, by The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company to National City Bank, as Bond Trustee. (incorporated by reference to OE’s 1991 Form 10-K , Exhibit 10-33)
  
10-6Amendment No. 6B dated as of December 30, 1991, to the Bond Guaranty dated as of October 1, 1973 by The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company to National City Bank, as Bond Trustee. (incorporated by reference to OE’s 1991 Form 10-K, Exhibit 10-34)
  
10-7Form of Collateral Trust Indenture among CTC Beaver Valley Funding Corporation, The Cleveland Electric Illuminating Company, The Toledo Edison Company and Irving Trust Company, as Trustee. (incorporated by reference to File No. 33-18755, Exhibit 4(a))
  


294



Exhibit
Number
10-8Form of Supplemental Indenture to Collateral Trust Indenture constituting Exhibit 10-10 above, including form of Secured Lease Obligation bond. (incorporated by reference to File No. 33-18755, Exhibit 4(b))
  
10-9Form of Collateral Trust Indenture among Beaver Valley II Funding Corporation, The Cleveland Electric Illuminating Company and The Toledo Edison Company and The Bank of New York, as Trustee. (incorporated by reference to File No. 33-46665, Exhibit (4)(a))

279
10-10Form of Supplemental Indenture to Collateral Trust Indenture constituting Exhibit 10-12 above, including form of Secured Lease Obligation Bond. (incorporated by reference to File No. 33-46665, Exhibit (4)(b))
  
10-11Form of Collateral Trust Indenture among CTC Mansfield Funding Corporation, Cleveland Electric, Toledo Edison and IBJ Schroder Bank & Trust Company, as Trustee. (incorporated by reference to File No. 33-20128, Exhibit 4(a))
  
10-12Form of Supplemental Indenture to Collateral Trust Indenture constituting Exhibit 10-14 above, including forms of Secured Lease Obligation bonds. (incorporated by reference to File No. 33-20128, Exhibit 4(b))
  
10-13Form of Facility Lease dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the limited partnership Owner Participant named therein, Lessor, and The Cleveland Electric Illuminating Company and The Toledo Edison Company, Lessee. (incorporated by reference to File No. 33-18755, Exhibit 4(c))
  
10-14Form of Amendment No. 1 to Facility Lease constituting Exhibit 10-16 above. (incorporated by reference to File No. 33-18755, Exhibit 4(e))
  
10-15Form of Facility Lease dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the corporate Owner Participant named therein, Lessor, and The Cleveland Electric Illuminating Company and The Toledo Edison Company, Lessees. (incorporated by reference to File No. 33-18755, Exhibit 4(d))
  
10-16Form of Amendment No. 1 to Facility Lease constituting Exhibit 10-18 above. (incorporated by reference to File No. 33-18755, Exhibit 4(f))
  
10-17Form of Facility Lease dated as of September 30, 1987 between Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Lessor, and The Cleveland Electric Illuminating Company and The Toledo Edison Company, Lessees. (incorporated by reference to File No. 33-20128, Exhibit 4(c))
  
10-18Form of Amendment No. 1 to the Facility Lease constituting Exhibit 10-20 above. (incorporated by reference to File No. 33-20128, Exhibit 4(f))
  
10-19Form of Participation Agreement dated as of September 15, 1987 among the limited partnership Owner Participant named therein, the Original Loan Participants listed in Schedule 1 thereto, as Original Loan Participants, CTC Beaver Valley Fund Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and The Cleveland Electric Illuminating Company and The Toledo Edison Company, as Lessees. (incorporated by reference to File No. 33-18755, Exhibit 28(a))
  
10-20Form of Amendment No. 1 to Participation Agreement constituting Exhibit 10-22 above (incorporated by reference to File No. 33-18755, Exhibit 28(c))
  
10-21Form of Participation Agreement dated as of September 15, 1987 among the corporate Owner Participant named therein, the Original Loan Participants listed in Schedule 1 thereto, as Owner Loan Participants, CTC Beaver Valley Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and The Cleveland Electric Illuminating Company and The Toledo Edison Company, as Lessees. (incorporated by reference to File No. 33-18755, Exhibit 28(b))
  
10-22Form of Amendment No. 1 to Participation Agreement constituting Exhibit 10-24 above (incorporated by reference to File No. 33-18755, Exhibit 28(d))

280
10-23Form of Participation Agreement dated as of September 30, 1987 among the Owner Participant named therein, the Original Loan Participants listed in Schedule II thereto, as Owner Loan Participants, CTC Mansfield Funding Corporation, Meridian Trust Company, as Owner Trustee, IBJ Schroder Bank & Trust Company, as Indenture Trustee, and The Cleveland Electric Illuminating Company and The Toledo Edison Company, as Lessees. (incorporated by reference to File No. 33-0128, Exhibit 28(a))
  
10-24Form of Amendment No. 1 to the Participation Agreement constituting Exhibit 10-26 above (incorporated by reference to File No. 33-20128, Exhibit 28(b))
  


295



Exhibit
Number
10-25Form of Ground Lease dated as of September 15, 1987 between Toledo Edison, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the Owner Participant named therein, Tenant. (incorporated by reference to File No. 33-18755, Exhibit 28(e))
  
10-26Form of Site Lease dated as of September 30, 1987 between Toledo Edison, Lessor, and Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Tenant. (incorporated by reference to File No. 33-20128, Exhibit 28(c))
  
10-27Form of Site Lease dated as of September 30, 1987 between The Cleveland Electric Illuminating Company, Lessor, and Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Tenant. (incorporated by reference to File No. 33-20128, Exhibit 28(d))
  
10-28Form of Amendment No. 1 to the Site Leases constituting Exhibits 10-29 and 10-30 above (incorporated by reference to File No. 33-20128, Exhibit 4(f))
  
10-29Form of Assignment, Assumption and Further Agreement dated as of September 15, 1987 among The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the Owner Participant named therein, The Cleveland Electric Illuminating Company, Duquesne, Ohio Edison Company, Pennsylvania Power Company and The Toledo Edison Company. (incorporated by reference to File No. 33-18755, Exhibit 28(f))
  
10-30Form of Additional Support Agreement dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the Owner Participant named therein and The Toledo Edison Company. (incorporated by reference to File No. 33-18755, Exhibit 28(g))
  
10-31Form of Support Agreement dated as of September 30, 1987 between Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, The Toledo Edison Company, The Cleveland Electric Illuminating Company, Duquesne, Ohio Edison Company and Pennsylvania Power Company. (incorporated by reference to File No. 33-20128, Exhibit 28(e))
  
10-32Form of Indenture, Bill of Sale, Instrument of Transfer and Severance Agreement dated as of September 30, 1987 between The Toledo Edison Company, Seller, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the Owner Participant named therein, Buyer. (incorporated by reference to File No. 33-18755, Exhibit 28(h))
  
10-33Form of Bill of Sale, Instrument of Transfer and Severance Agreement dated as of September 30, 1987 between The Toledo Edison Company, Seller, and Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Buyer. (incorporated by reference to File No. 33-20128, Exhibit 28(f))
  
10-34Form of Bill of Sale, Instrument of Transfer and Severance Agreement dated as of September 30, 1987 between The Cleveland Electric Illuminating Company, Seller, and Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Buyer. (incorporated by reference to File No. 33-20128, Exhibit 28(g))

281
10-35Forms of Refinancing Agreement, including exhibits thereto, among the Owner Participant named therein, as Owner Participant, CTC Beaver Valley Funding Corporation, as Funding Corporation, Beaver Valley II Funding Corporation, as New Funding Corporation, The Bank of New York, as Indenture Trustee, The Bank of New York, as New Collateral Trust Trustee, and The Cleveland Electric Illuminating Company and The Toledo Edison Company, as Lessees. (incorporated by reference to File No. 33-46665, Exhibit (28)(e)(i))
  
10-36Form of Amendment No. 2 to Facility Lease among Citicorp Lescaman, Inc., The Cleveland Electric Illuminating Company and The Toledo Edison Company. (incorporated by reference to CEI’s Form S-4 filed March 10, 1998, Exhibit 10(a), File No. 333-47651)
  
10-37Form of Amendment No. 3 to Facility Lease among Citicorp Lescaman, Inc., The Cleveland Electric Illuminating Company and The Toledo Edison Company. (incorporated by reference to CEI’s Form S-4 filed March 10, 1998, Exhibit 10(b), File No. 333-47651)
  
10-38Form of Amendment No. 2 to Facility Lease among US West Financial Services, Inc., The Cleveland Electric Illuminating Company and The Toledo Edison Company. (incorporated by reference to CEI’s Form S-4 filed March 10, 1998, Exhibit 10(c), File No. 333-47651)
  
10-39Form of Amendment No. 3 to Facility Lease among US West Financial Services, Inc., The Cleveland Electric Illuminating Company and The Toledo Edison Company. (incorporated by reference to CEI’s Form S-4 filed March 10, 1998, Exhibit 10(d), File No. 333-47651)
  
10-40Form of Amendment No. 2 to Facility Lease among Midwest Power Company, The Cleveland Electric Illuminating Company and The Toledo Edison Company. (incorporated by reference to CEI’s Form S-4 filed March 10, 1998 , Exhibit 10(e), File No. 333-47651)
  


296



Exhibit
Number
10-41Centerior Energy Corporation Equity Compensation Plan. (incorporated by reference to Centerior Energy Corporation’s Form S-8 filed May 26, 1995, Exhibit 99, File No. 33-59635)
  
10-42Revised Power Supply Agreement, dated December 8, 2006, among FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company and The Toledo Edison Company. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.34, File No. 333-145140-01)
10-43Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power Company, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein. (incorporated by reference to FE's Form 10-Q filed August 2, 2011, Exhibit 10.1, File No. 333-21011)

3.     Exhibits – CEI

3. Exhibits — CEI
Exhibit
Number
3-1
Amended and Restated Articles of Incorporation of The Cleveland Electric Illuminating Company, Effective December 21, 2007. (incorporated(incorporated by reference to CEI’s Form 10-K filed February 29, 2008, Exhibit 3.3, File No. 001-02323)
  
3-2
Amended and Restated Code of Regulations of The Cleveland Electric Illuminating Company, dated December 14, 2007. (incorporated(incorporated by reference to CEI’s Form 10-K filed February 29, 2008, Exhibit 3.4, File No. 001-02323)
  
(B) 4-1
Mortgage and Deed of Trust between The Cleveland Electric Illuminating Company and Guaranty Trust Company of New York (now The Chase Manhattan Bank (National Association)), as Trustee, dated July 1, 1940. (incorporated(incorporated by reference to File No. 2-4450, Exhibit 7(a))
  
 Supplemental Indentures between The Cleveland Electric Illuminating Company and the Trustee, supplemental to Exhibit 4-1, dated as follows:
4-1(a)
July 1, 1940 (incorporated(incorporated by reference to File No. 2-4450, Exhibit 7(b))
4-1(b)
August 18, 1944 (incorporated(incorporated by reference to File No. 2-9887, Exhibit 4(c))
4-1(c)
December 1, 1947 (incorporated(incorporated by reference to File No. 2-7306, Exhibit 7(d))
4-1(d)
September 1, 1950 (incorporated(incorporated by reference to File No. 2-8587, Exhibit 7(c))
4-1(e)
June 1, 1951 (incorporated(incorporated by reference to File No. 2-8994, Exhibit 7(f))
4-1(f)
May 1, 1954 (incorporated(incorporated by reference to File No. 2-10830, Exhibit 4(d))
4-1(g)
March 1, 1958 (incorporated(incorporated by reference to File No. 2-13839, Exhibit 2(a)(4))
4-1(h)
April 1, 1959 (incorporated(incorporated by reference to File No. 2-14753, Exhibit 2(a)(4))
4-1(i)
December 20, 1967 (incorporated(incorporated by reference to File No. 2-30759, Exhibit 2(a)(4))
4-1(j)
January 15, 1969 (incorporated(incorporated by reference to File No. 2-30759, Exhibit 2(a)(5))
4-1(k)
November 1, 1969 (incorporated(incorporated by reference to File No. 2-35008, Exhibit 2(a)(4))
4-1(l)
June 1, 1970 (incorporated(incorporated by reference to File No. 2-37235, Exhibit 2(a)(4))

282
4-1(m)
November 15, 1970 (incorporated(incorporated by reference to File No. 2-38460, Exhibit 2(a)(4))
4-1(n)
May 1, 1974 (incorporated(incorporated by reference to File No. 2-50537, Exhibit 2(a)(4))
4-1(o)
April 15, 1975 (incorporated(incorporated by reference to File No. 2-52995, Exhibit 2(a)(4))
4-1(p)
April 16, 1975 (incorporated(incorporated by reference to File No. 2-53309, Exhibit 2(a)(4))


297



Exhibit
Number
4-1(q)
May 28, 1975 (incorporated(incorporated by reference to Form 8-A filed June 5, 1975, Exhibit 2(c), File No. 1-2323)
4-1(r)
February 1, 1976 (incorporated(incorporated by reference to 1975 Form 10-K, Exhibit 3(d)(6), File No. 1-2323)
4-1(s)
November 23, 1976 (incorporated(incorporated by reference to File No. 2-57375, Exhibit 2(a)(4))
4-1(t)
July 26, 1977 (incorporated(incorporated by reference to File No. 2-59401, Exhibit 2(a)(4))
4-1(u)
September 7, 1977 (incorporated(incorporated by reference to File No. 2-67221, Exhibit 2(a)(5))
4-1(v)
May 1, 1978 (incorporated(incorporated by reference to June 1978 Form 10-Q, Exhibit 2(b), File No. 1-2323)
4-1(w)
September 1, 1979 (incorporated(incorporated by reference to September 1979 Form 10-Q, Exhibit 2(a), File No. 1-2323)
4-1(x)
April 1, 1980 (incorporated(incorporated by reference to September 1980 Form 10-Q, Exhibit 4(a)(2), File No. 1-2323)
4-1(y)
April 15, 1980 (incorporated(incorporated by reference to September 1980 Form 10-Q, Exhibit 4(b), File No. 1-2323)
4-1(z)
May 28, 1980 (incorporated(incorporated by reference to Amendment No. 1, Exhibit 2(a)(4), File No. 2-67221)
4-1(aa)
June 9, 1980 (incorporated(incorporated by reference to September 1980 Form 10-Q, Exhibit 4(d), File No. 1-2323)
4-1(bb)
December 1, 1980 (incorporated(incorporated by reference to 1980 Form 10-K, Exhibit 4(b)(29), File No. 1-2323)
4-1(cc)
July 28, 1981 (incorporated(incorporated by reference to September 1981 Form 10-Q, Exhibit 4(a), File No. 1-2323)
4-1(dd)
August 1, 1981 (incorporated(incorporated by reference to September 1981 Form 10-Q, Exhibit 4(b), File No. 1-2323)
4-1(ee)
March 1, 1982 (incorporated(incorporated by reference to Amendment No. 1, Exhibit 4(b)(3), File No. 2-76029)
4-1(ff)
July 15, 1982 (incorporated(incorporated by reference to September 1982 Form 10-Q, Exhibit 4(a), File No. 1-2323)
4-1(gg)
September 1, 1982 (incorporated(incorporated by reference to September 1982 Form 10-Q, Exhibit 4(a)(1), File No. 1-2323)
4-1(hh)
November 1, 1982 (incorporated(incorporated by reference to September 1982 Form 10-Q, Exhibit (a)(2), File No. 1-2323)
4-1(ii)
November 15, 1982 (incorporated(incorporated by reference to 1982 Form 10-K, Exhibit 4(b)(36), File No. 1-2323)
4-1(jj)
May 24, 1983 (incorporated(incorporated by reference to June 1983 Form 10-Q, Exhibit 4(a), File No. 1-2323)
4-1(kk)
May 1, 1984 (incorporated(incorporated by reference to June 1984 Form 10-Q, Exhibit 4, File No. 1-2323)
4-1(ll)
May 23, 1984 (incorporated(incorporated by reference to Form 8-K dated May 22, 1984, Exhibit 4, File No. 1-2323)
4-1(mm)
June 27, 1984 (incorporated(incorporated by reference to Form 8-K dated June 11, 1984, Exhibit 4, File No. 1-2323)
4-1(nn)
September 4, 1984 (incorporated(incorporated by reference to 1984 Form 10-K, Exhibit 4b(41), File No. 1-2323)
4-1(oo)
November 14, 1984 (incorporated(incorporated by reference to 1984 Form 10 K, Exhibit 4b(42), File No. 1-2323)
4-1(pp)
November 15, 1984 (incorporated(incorporated by reference to 1984 Form 10-K, Exhibit 4b(43), File No. 1-2323)
4-1(qq)
April 15, 1985 incorporated by reference to (Form 8-K dated May 8, 1985, Exhibit 4(a), File No. 1-2323)
4-1(rr)
May 28, 1985 (incorporated(incorporated by reference to Form 8-K dated May 8, 1985, Exhibit 4(b), File No. 1-2323)
4-1(ss)
August 1, 1985 (incorporated(incorporated by reference to September 1985 Form 10-Q, Exhibit 4, File No. 1-2323)


298



Exhibit
Number
4-1(tt)
September 1, 1985 (incorporated(incorporated by reference to Form 8-K dated September 30, 1985, Exhibit 4, File No. 1-2323)
4-1(uu)
November 1, 1985 (incorporated(incorporated by reference to Form 8-K dated January 31, 1986, Exhibit 4, File No. 1-2323)
4-1(vv)
April 15, 1986 (incorporated(incorporated by reference to March 1986 Form 10-Q, Exhibit 4, File No. 1-2323)
4-1(ww)
May 14, 1986 (incorporated(incorporated by reference to June 1986 Form 10-Q, Exhibit 4(a), File No. 1-2323)
4-1(xx)
May 15, 1986 (incorporated(incorporated by reference to June 1986 Form 10-Q, Exhibit 4(b), File No. 1-2323)
4-1(yy)
February 25, 1987 (incorporated(incorporated by reference to 1986 Form 10-K, Exhibit 4b(52), File No. 1-2323)

283
4-1(zz)
October 15, 1987 (incorporated(incorporated by reference to September 1987 Form 10-Q, Exhibit 4, File No. 1-2323)
4-1(aaa)
February 24, 1988 (incorporated(incorporated by reference to 1987 Form 10-K, Exhibit 4b(54), File No. 1-2323)
4-1(bbb)
September 15, 1988 (incorporated(incorporated by reference to 1988 Form 10-K, Exhibit 4b(55), File No. 1-2323)
4-1(ccc)
May 15, 1989 (incorporated(incorporated by reference to File No. 33-32724, Exhibit 4(a)(2)(i))
4-1(ddd)
June 13, 1989 (incorporated(incorporated by reference to File No. 33-32724, Exhibit 4(a)(2)(ii))
4-1(eee)
October 15, 1989 (incorporated(incorporated by reference to File No. 33-32724, Exhibit 4(a)(2)(iii))
4-1(fff)
January 1, 1990 (incorporated(incorporated by reference to 1989 Form 10-K, Exhibit 4b(59), File No. 1-2323)
4-1(ggg)
June 1, 1990 (incorporated(incorporated by reference to September 1990 Form 10-Q, Exhibit 4(a), File No. 1-2323)
4-1(hhh)
August 1, 1990 (incorporated(incorporated by reference to September 1990 Form 10-Q, Exhibit 4(b), File No. 1-2323)
4-1(iii)
May 1, 1991 (incorporated(incorporated by reference to June 1991 Form 10-Q, Exhibit 4(a), File No. 1-2323)
4-1(jjj)
May 1, 1992 (incorporated(incorporated by reference to File No. 33-48845, Exhibit 4(a)(3))
4-1(kkk)
July 31, 1992 (incorporated(incorporated by reference to File No. 33-57292, Exhibit 4(a)(3))
4-1(lll)
January 1, 1993 (incorporated(incorporated by reference to 1992 Form 10-K, Exhibit 4b(65), File No. 1-2323)
4-1(mmm)
February 1, 1993 (incorporated(incorporated by reference to 1992 Form 10-K, Exhibit 4b(66), File No. 1-2323)
4-1(nnn)
May 20, 1993 (incorporated(incorporated by reference to Form 8-K dated July 14, 1993, Exhibit 4(a), File No. 1-2323)
4-1(ooo)
June 1, 1993 (incorporated(incorporated by reference to Form 8-K dated July 14, 1993, Exhibit 4(b), File No. 1-2323)
4-1(ppp)
September 15, 1994 (incorporated(incorporated by reference to CEI’s Form 10-Q filed November 14, 1994, Exhibit 4(a), File No. 001-02323)
4-1(qqq)
May 1, 1995 (incorporated(incorporated by reference to CEI’s Form 10-Q filed November 13, 1995, Exhibit 4(a), File No. 001-02323)
4-1(rrr)
May 2, 1995 (incorporated(incorporated by reference to CEI’s Form 10-Q filed November 13, 1995, Exhibit 4(b) , File No. 001-02323)
4-1(sss)
June 1, 1995 (incorporated(incorporated by reference to CEI’s Form 10-Q filed November 13, 1995, Exhibit 4(c), File No. 001-02323)
4-1(ttt)
July 15, 1995 (incorporated(incorporated by reference to CEI’s Form 10-K filed March 29, 1996, Exhibit 4b(73), File No. 001-02323)
4-1(uuu)
August 1, 1995 (incorporated(incorporated by reference to CEI’s Form 10-K filed March 29, 1996, Exhibit 4b(74), File No. 001-02323)
4-1(vvv)June 15, 1997 (incorporated by reference to CEI’s Form S-4 filed September 18, 2007, Exhibit 4(a), File No. 333-35931)


299



Exhibit
Number
4-1(www)October 15, 1997 (incorporated by reference to CEI’s Form S-4 filed March 10, 1998, Exhibit 4(a), File No. 333-47651)
4-1(xxx)June 1, 1998 (incorporated by reference to CEI’s Form S-4, Exhibit 4b(77), File No. 333-72891)
4-1(yyy)October 1, 1998 (incorporated by reference to CEI’s Form S-4 filed February 24, 1999, Exhibit 4b(78), File No. 333-72891)
4-1(zzz)October 1, 1998 (incorporated by reference to CEI’s Form S-4 filed February 24, 1999, Exhibit 4b(79), File No. 333-72891)
4-1(aaaa)February 24, 1999 (incorporated by reference to CEI’s Form S-4 filed February 24, 1999, Exhibit 4b(80), File No. 333-72891)
4-1(bbbb)
September 29, 1999 (incorporated(incorporated by reference to CEI’s Form 10-K filed March 29, 2000, Exhibit 4b(81), File No. 001-02323)
4-1(cccc)
January 15, 2000 (incorporated(incorporated by reference to CEI’s Form 10-K filed March 29, 2000, Exhibit 4b(82), File No. 001-02323)
4-1(dddd)
May 15, 2002 (incorporated(incorporated by reference to CEI’s Form 10-K filed March 26, 2003, Exhibit 4b(83), File No. 001-02323)
4-1(eeee)
October 1, 2002 (incorporated(incorporated by reference to CEI’s Form 10-K filed March 26, 2003, Exhibit 4b(84), File No. 001-02323)
4-1(ffff)
Supplemental Indenture dated as of September 1, 2004 (incorporated(incorporated by reference to CEI’s Form 10-Q filed November 4, 2004, Exhibit 4-1(85), File No. 001-02323)
4-1(gggg)
Supplemental Indenture dated as of October 1, 2004 (incorporated(incorporated by reference to CEI’s Form 10-Q filed November 4, 2004, Exhibit 4-1(86), File No. 001-02323)
4-1(hhhh)
Supplemental Indenture dated as of April 1, 2005 (incorporated(incorporated by reference to CEI’s Form 10-Q filed August 1, 2005, Exhibit 4.1, File No. 001-02323)
4-1(iiii)
Supplemental Indenture dated as of July 1, 2005 (incorporated(incorporated by reference to CEI’s Form 10-Q filed August 1, 2005, Exhibit 4.2, File No. 001-02323)

284
4-1(jjjj)
Eighty-Ninth Supplemental Indenture, dated as of November 1, 2008 (relating to First Mortgage Bonds, 8.875% Series due 2018). (incorporated(incorporated by reference to CEI’s Form 8-K filed November 19, 2008, Exhibit 4.1, File No. 001-02323)
4-1(kkk)
Ninetieth Supplemental Indenture, dated as of August 1, 2009 (including Form of First Mortgage Bonds, 5.50% Series due 2024). (incorporated by reference to CEI'sCEI’s Form 8-K filed on August 18, 2009, Exhibit 4.1, File No. 001-02323)
  
4-2Form of Note Indenture between The Cleveland Electric Illuminating Company and The Chase Manhattan Bank, as Trustee dated as of October 24, 1997. (incorporated by reference to CEI'sCEI’s Form S-4 filed March 10, 1998, Exhibit 4(b), File No. 333-47651)
  
4-2(a)Form of Supplemental Note Indenture between The Cleveland Electric Illuminating Company and The Chase Manhattan Bank, as Trustee dated as of October 24, 1997. (incorporated by reference to CEI'sCEI’s Form S-4 filed March 10, 1998, Exhibit 4(c), File No. 333-47651)
  
4-3Indenture dated as of December 1, 2003 between The Cleveland Electric Illuminating Company and JPMorgan Chase Bank, as Trustee. (incorporated by reference to CEI'sCEI’s Form 10-K filed March 15, 2004, Exhibit 4-1, File No. 001-02323)
  
4-3(a)Officer’s Certificate (including the form of 5.95% Senior Notes due 2036), dated as of December 11, 2006. (incorporated by reference to CEI'sCEI’s Form 8-K filed December 12, 2006, Exhibit 4, File No. 001-02323)
4-3(b)Officer’s Certificate (including the form of 5.70% Senior Notes due 2017), dated as of March 27, 2007. (incorporated by reference to CEI'sCEI’s Form 8-K filed March 28, 2007, Exhibit 4, File No. 001-02323)
  
10-1CEI Nuclear Purchase and Sale Agreement by and between The Cleveland Electric Illuminating Company and FirstEnergy Nuclear Generation Corp. (incorporated by reference to CEI'sCEI’s Form 10-Q filed August 1, 2005, Exhibit 10.1, File No. 001-02323)
  
10-2CEI Fossil Purchase and Sale Agreement by and between The Cleveland Electric Illuminating Company (Seller) and FirstEnergy Generation Corp. (Purchaser). (incorporated by reference to CEI'sCEI’s Form 10-Q filed August 1, 2005, Exhibit 10.2, File No. 001-02323)


300



Exhibit
Number
  
10-3
CEI Fossil Security Agreement, dated October 24, 2005, by and between FirstEnergy Generation Corp. and The Cleveland Electric Illuminating Company. (Form S-4/A filed August 20, 2007, Exhibit 10.16, File No. 333-145140-01)333-145140-01)
  
10-4
CEI Nuclear Security Agreement, dated December 16, 2005, by and between FirstEnergy Nuclear Generation Corp. and The Cleveland Electric Illuminating Company. (incorporated(incorporated by reference to FE'sFE’s Form S-4/A filed August 20, 2007, Exhibit 10.26, File No. 333-145140-01)333-145140-01)
  
10-5Nuclear Sale/Leaseback Power Supply Agreement dated as of October 14, 2005 between Ohio Edison Company and The Toledo Edison Company (Sellers) and FirstEnergy Nuclear Generation Corp. (Buyer). (incorporated by reference to CEI'sCEI’s Form 10-K filed March 2, 2006, Exhibit 10-64, File No. 001-02323)
  
10-6Power Supply Agreement dated as of October 31, 2005 between FirstEnergy Solutions Corp. (Seller) and the FirstEnergy Operating Companies – Ohio Edison Company, The Cleveland Electric Illuminating Company and The Toledo Edison Company (Buyers). (incorporated by reference to CEI's Form 10-K filed March 2, 2006, Exhibit 10-66, File No. 001-02323)
 
10-7Mansfield Power Supply Agreement dated as of October 14, 2005 between The Cleveland Electric Illuminating Company and The Toledo Edison Company (Sellers) and FirstEnergy Generation Corp. (Buyer). (incorporated by reference to CEI'sCEI’s Form 10-K filed March 2, 2006, Exhibit 10-65, File No. 001-02323)
  
10-8Master SSO Supply Agreement, entered into May 18, 2009, by and between The Cleveland Electric Illuminating Company, the Toledo Edison Company and Ohio Edison Company and FirstEnergy Solutions Corp. (incorporated by reference to CEI's Form 10-Q filed August 3, 2009, Exhibit 10.2, File No. 001-02323)

285
(A) 12-4Consolidated ratios of earnings to fixed charges.
  
(A) 31-1Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
  
(A) 23-3Consent of Independent Registered Public Accounting Firm
 
(A) 31-2
Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
  
(A) 32Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. §1350.
  
(A)Provided herein in electronic format as an exhibit.
  
(B)Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, CEI has not filed as an exhibit to this Form 10-K any instrument with respect to long-term debt if the total amount of securities authorized thereunder does not exceed 10% of the total assets of CEI, but hereby agrees to furnish to the Commission on request any such instruments.

3.     Exhibits – TE

3. Exhibits — TE
Exhibit
Number
3-1
Amended and Restated Articles of Incorporation of The Toledo Edison Company, effective December 18, 2007. (incorporated(incorporated by reference to TE’s Form 10-K filed February 29, 2008, Exhibit 3c, File No. 001-03583)
  
3-2
Amended and Restated Code of Regulations of The Toledo Edison Company, dated December 14, 2007. (incorporated(incorporated by reference to TE’s Form 10-K filed February 29, 2008, Exhibit 3d, File No. 001-03583)
  
(B) 4-1
Indenture, dated as of April 1, 1947, between The Toledo Edison Company and The Chase National Bank of the City of New York (now The Chase Manhattan Bank (National Association)), as Trustee. (incorporated(incorporated by reference to File No. 2-26908, Exhibit 2(b))
  
 Supplemental Indentures between The Toledo Edison Company and the Trustee, supplemental to Exhibit 4-1, dated as follows:
4-1(a)
September 1, 1948 (incorporated(incorporated by reference to File No. 2-26908, Exhibit 2(d))
4-1(b)
April 1, 1949 (incorporated(incorporated by reference to File No. 2-26908, Exhibit 2(e))
4-1(c)
December 1, 1950 (incorporated(incorporated by reference to File No. 2-26908, Exhibit 2(f))
4-1(d)
March 1, 1954 (incorporated(incorporated by reference to File No. 2-26908, Exhibit 2(g))
4-1(e)
February 1, 1956 (incorporated(incorporated by reference to File No. 2-26908, Exhibit 2(h))
4-1(f)
May 1, 1958 (incorporated(incorporated by reference to File No. 2-59794, Exhibit 5(g))
4-1(g)
August 1, 1967 (incorporated(incorporated by reference to File No. 2-26908, Exhibit 2(c))
4-1(h)
November 1, 1970 (incorporated(incorporated by reference to File No. 2-38569, Exhibit 2(c))


301



Exhibit
Number
4-1(i)
August 1, 1972 (incorporated(incorporated by reference to File No. 2-44873, Exhibit 2(c))
4-1(j)
November 1, 1973 (incorporated(incorporated by reference to File No. 2-49428, Exhibit 2(c))
4-1(k)
July 1, 1974 (incorporated(incorporated by reference to File No. 2-51429, Exhibit 2(c))
4-1(l)
October 1, 1975 (incorporated(incorporated by reference to File No. 2-54627, Exhibit 2(c))
4-1(m)
June 1, 1976 (incorporated(incorporated by reference to File No. 2-56396, Exhibit 2(c))
4-1(n)
October 1, 1978 (incorporated(incorporated by reference to File No. 2-62568, Exhibit 2(c))
4-1(o)
September 1, 1979 (incorporated(incorporated by reference to File No. 2-65350, Exhibit 2(c))
4-1(p)
September 1, 1980 (incorporated(incorporated by reference to File No. 2-69190, Exhibit 4(s))
4-1(q)
October 1, 1980 (incorporated(incorporated by reference to File No. 2-69190, Exhibit 4(c))
4-1(r)
April 1, 1981 (incorporated(incorporated by reference to File No. 2-71580, Exhibit 4(c))
4-1(s)
November 1, 1981 (incorporated(incorporated by reference to File No. 2-74485, Exhibit 4(c))
4-1(t)
June 1, 1982 (incorporated(incorporated by reference to File No. 2-77763, Exhibit 4(c))
4-1(u)
September 1, 1982 (incorporated(incorporated by reference to File No. 2-87323, Exhibit 4(x))
4-1(v)
April 1, 1983 (incorporated(incorporated by reference to March 1983 Form 10-Q, Exhibit 4(c), File No. 1-3583)
4-1(w)
December 1, 1983 (incorporated(incorporated by reference to 1983 Form 10-K, Exhibit 4(x), File No. 1-3583)
4-1(x)
April 1, 1984 (incorporated(incorporated by reference to File No. 2-90059, Exhibit 4(c))
4-1(y)
October 15, 1984 (incorporated(incorporated by reference to 1984 Form 10-K, Exhibit 4(z), File No. 1-3583)
4-1(z)
October 15, 1984 (incorporated(incorporated by reference to 1984 Form 10-K, Exhibit 4(aa), File No. 1-3583)
4-1(aa)
August 1, 1985 (incorporated(incorporated by reference to File No. 33-1689, Exhibit 4(dd))
4-1(bb)
August 1, 1985 (incorporated(incorporated by reference to File No. 33-1689, Exhibit 4(ee))
4-1(cc)December 1, 1985 (incorporated by reference to File No. 33-1689, Exhibit 4(c))
4-1(dd)March 1, 1986 (incorporated by reference to 1986 Form 10-K, Exhibit 4b(31), File No. 1-3583)
4-1(ee)October 15, 1987 (incorporated by reference to September 30, 1987 Form 10-Q, Exhibit 4, File No. 1-3583)
4-1(ff)September 15, 1988 (incorporated by reference to 1988 Form 10-K, Exhibit 4b(33), File No. 1-3583)
4-1(gg)June 15, 1989 (incorporated by reference to 1989 Form 10-K, Exhibit 4b(34), File No. 1-3583)
4-1(hh)October 15, 1989 (incorporated by reference to 1989 Form 10-K, Exhibit 4b(35), File No. 1-3583)
4-1(ii)May 15, 1990 (incorporated by reference to June 30, 1990 Form 10-Q, Exhibit 4, File No. 1-3583)
4-1(jj)March 1, 1991 (incorporated by reference to June 30, 1991 Form 10-Q, Exhibit 4(b), File No. 1-3583)
4-1(kk)May 1, 1992 (incorporated by reference to File No. 33-48844, Exhibit 4(a)(3))


302
286


4-1(cc)
December 1, 1985 (incorporated by reference to File No. 33-1689, Exhibit 4(c))

4-1(dd)
March 1, 1986 (incorporated by reference to 1986 Form 10-K, Exhibit 4b(31), File No. 1-3583)
4-1(ee)
Exhibit
Number
October 15, 1987 (incorporated by reference to September 30, 1987 Form 10-Q, Exhibit 4, File No. 1-3583)
4-1(ff)
September 15, 1988 (incorporated by reference to 1988 Form 10-K, Exhibit 4b(33), File No. 1-3583)
4-1(gg)
June 15, 1989 (incorporated by reference to 1989 Form 10-K, Exhibit 4b(34), File No. 1-3583)
4-1(hh)
October 15, 1989 (incorporated by reference to 1989 Form 10-K, Exhibit 4b(35), File No. 1-3583)
4-1(ii)
May 15, 1990 (incorporated by reference to June 30, 1990 Form 10-Q, Exhibit 4, File No. 1-3583)
4-1(jj)
March 1, 1991 (incorporated by reference to June 30, 1991 Form 10-Q, Exhibit 4(b), File No. 1-3583)
4-1(kk)
May 1, 1992 (incorporated by reference to File No. 33-48844, Exhibit 4(a)(3))
4-1(ll)
August 1, 1992 (incorporated(incorporated by reference to 1992 1992 Form 10-K, Exhibit 4b(39), File No. 1-3583)
4-1(mm)
October 1, 1992 (incorporated(incorporated by reference to 1992 1992 Form 10-K, Exhibit 4b(40), File No. 1-3583)
4-1(nn)
January 1, 1993 (incorporated(incorporated by reference to 1992 1992 Form 10-K, Exhibit 4b(41), File No. 1-3583)
4-1(oo)
September 15, 1994 (incorporated(incorporated by reference to TE’s Form 10-Q filed November 14, 1994, Exhibit 4(b), File No. 001-03583)
4-1(pp)
May 1, 1995 (incorporated(incorporated by reference to TE’s Form 10-Q filed November 14, 1994, Exhibit 4(d), File No. 001-03583)
4-1(qq)
June 1, 1995 (incorporated(incorporated by reference to TE’s Form 10-Q filed November 14, 1994, Exhibit 4(e), File No. 001-03583)
4-1(rr)
July 14, 1995 (incorporated(incorporated by reference to TE’s Form 10-Q filed November 14, 1994, Exhibit 4(f), File No. 001-03583)
4-1(ss)
July 15, 1995 (incorporated(incorporated by reference to TE’s Form 10-Q filed November 14, 1994, Exhibit 4(g), File No. 1-3583)
4-1(tt)
August 1, 1997 (incorporated(incorporated by reference to TE’s Form 10-K filed March 29, 1999, Exhibit 4b(47), File No. 001-03583)
4-1(uu)
June 1, 1998 (incorporated(incorporated by reference to TE’s Form 10-K filed March 29, 1999, Exhibit 4b(48), File No. 001-03583)
4-1(vv)
January 15, 2000 (incorporated(incorporated by reference to TE’s Form 10-K filed March 29, 1999, Exhibit 4b(49), File No. 001-03583)
4-1(ww)
May 1, 2000 (incorporated(incorporated by reference to TE’s Form 10-K filed April 16, 2000, Exhibit 4b(50), File No. 001-03583)
4-1(xx)
September 1, 2000 (incorporated(incorporated by reference to TE’s Form 10-K filed April 16, 2001, Exhibit 4b(51), File No. 001-03583)
4-1(yy)
October 1, 2002 (incorporated(incorporated by reference to TE’s Form 10-K filed March 26, 2003, Exhibit 4b(52), File No. 001-03583)
4-1(zz)
April 1, 2003 (incorporated(incorporated by reference to TE’s Form 10-K filed March 15, 2004, Exhibit 4b(53), File No. 001-03583)
4-1(aaa)
September 1, 2004 (incorporated(incorporated by reference to TE’s 10-Q filed November 4, 2004, Exhibit 4.2.56, File No. 001-03583)
4-1(bbb)
April 1, 2005 (incorporated(incorporated by reference to TE’s June 2005 10-Q, Exhibit 4.1, File No. 001-03583)
4-1(ccc)
April 23, 2009 (incorporated(incorporated by reference to TE’s Form 8-K filed April 24, 2009, Exhibit 4.3, File No. 001-03583)
4-1(ddd)
April 24, 2009 (incorporated(incorporated by reference to TE’s Form 8-K filed April 24, 2009, Exhibit 4.4, File No. 001-03583)
  
4-2Indenture dated as of November 1, 2006, between The Toledo Edison Company and The Bank of New York Trust Company, N.A. (incorporated by reference to TE’s Form 10-K filed February 28, 2007, Exhibit 4-2, File No. 001-03583)
  
4-2(a)Officer’s Certificate (including the form of 6.15% Senior Notes due 2037), dated November 16, 2006. (incorporated by reference to TE’s Form 8-K filed November 17, 2006, Exhibit 4, File No. 001-03583)
4-2(b)First Supplemental Indenture, dated as of April 24, 2009, between the Toledo Edison Company and The Bank of New York Mellon Trust Company, N.A., as trustee to the Indenture dated as of November 1, 2006 (incorporated by reference to TE’s Form 8-K filed April 24, 2009, Exhibit 4.1, File No. 001-03583)

287
4-2(c)Officer’s Certificate (including the Form of the 7.25% Senior Secured Notes due 2020), dated April 24, 2009 (incorporated by reference to TE’s Form 8-K filed April 24, 2009, Exhibit 4.2, File No. 001-03583)
  
10-1TE Nuclear Purchase and Sale Agreement by and between The Toledo Edison Company (Seller) and FirstEnergy Nuclear Generation Corp. (Purchaser). (incorporated by reference to TE’s Form 10-Q filed August 1, 2005, Exhibit 10.1, File No. 001-03583)
  
10-2TE Fossil Purchase and Sale Agreement by and between The Toledo Edison Company (Seller) and FirstEnergy Generation Corp. (Purchaser). (incorporated by reference to TE’s Form 10-Q filed August 1, 2005, Exhibit 10.2, File No. 001-03583)
  


303



Exhibit
Number
10-3
TE Fossil Security Agreement, dated October 24, 2005, by and between FirstEnergy Generation Corp. and The Toledo Edison Company. (incorporated(incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.24, File No. 333-145140-01)333-145140-01)
  
10-4Nuclear Sale/Leaseback Power Supply Agreement dated as of October 14, 2005 between Ohio Edison Company and The Toledo Edison Company (Sellers) and FirstEnergy Nuclear Generation Corp. (Buyer). (incorporated by reference to TE’s Form 10-K filed March 2, 2006, Exhibit 10-64, File No. 001-03583)
  
10-5Power Supply Agreement dated as of October 31, 2005 between FirstEnergy Solutions Corp. (Seller) and the FirstEnergy Operating Companies – Ohio Edison Company, The Cleveland Electric Illuminating Company and The Toledo Edison Company (Buyers). (incorporated by reference to TE’s Form 10-K, Exhibit 10-6, File No. 001-03583)
 
10-6Mansfield Power Supply Agreement dated as of October 14, 2005 between The Cleveland Electric Illuminating Company and The Toledo Edison Company (Sellers) and FirstEnergy Generation Corp. (Buyer). (incorporated by reference to TE’s Form 10-K, Exhibit 10-65, File No. 001-03583)
  
10-7Master SSO Supply Agreement, entered into May 18, 2009, by and between The Cleveland Electric Illuminating Company, the Toledo Edison Company and Ohio Edison Company and FirstEnergy Solutions Corp. (incorporated by reference to TE’s Form 10-Q filed August 3, 2009, Exhibit 10.2, File No. 001-03583
 
(A) 12-5Consolidated ratios of earnings to fixed charges.
  
(A) 23-4Consent of Independent Registered Public Accounting Firm
 
(A) 31-1Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
  
(A) 31-2Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
  
(A) 32Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. §1350.
  
(A)Provided herein in electronic format as an exhibit.
  
(B)Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, TE has not filed as an exhibit to this Form 10-K any instrument with respect to long-term debt if the total amount of securities authorized thereunder does not exceed 10% of the total assets of TE, but hereby agrees to furnish to the Commission on request any such instruments.



3.     Exhibits – JCP&L304


3. Exhibits — JCP&L
Exhibit
Number
3-1
Amended and Restated Certificate of Incorporation of Jersey Central Power & Light Company, filed February 14, 2008. (incorporated(incorporated by reference to JCP&L’s Form 10-K filed February 29, 2008, Exhibit 3-D, File No. 001-03141)

288


3-2
Amended and Restated Bylaws of Jersey Central Power & Light Company, dated January 9, 2008. (incorporated(incorporated by reference to JCP&L’s Form 10-K filed February 29, 2008, Exhibit 3-E, File No. 001-03141)
  
4-1
Senior Note Indenture, dated as of July 1, 1999, between Jersey Central Power & Light Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee to United States Trust Company of New York. (incorporated(incorporated by reference to JCP&L’s Form S-3 filed May 18, 1999, Exhibit 4-A, File No. 333-78717)
  
4-1(a)
First Supplemental Indenture, dated October 31, 2007, between Jersey Central Power & Light Company, The Bank of New York, as resigning trustee, and The Bank of New York Trust Company, N.A., as successor trustee. (incorporated(incorporated by reference to JCP&L’s Form S-4/A filed November 11, 2007, Exhibit 4-2, File No. 333-146968)
4-1(b)
Form of Jersey Central Power & Light Company 6.40% Senior Note due 2036. (incorporated(incorporated by reference to JCP&L’s Form 8-K filed May 12, 2006, Exhibit 10-1, File No. 001-03141)
4-1(c)
Form of 7.35% Senior Notes due 2019. (incorporated(incorporated by reference to JCP&L’s Form 8-K filed January 27, 2009, Exhibit 4.1, File No. 001-03141)
  
10-1
Indenture dated as of August 10, 2006 between JCP&L Transition Funding II LLC as Issuer and The Bank of New York as Trustee. (incorporated(incorporated by reference to JCP&L’s Form 8-K filed August 10, 2006, Exhibit 4-1,, File No. 001-03141)001-03141)
  
10-2
2006-A Series Supplement dated as of August 10, 2006 between JCP&L Transition Funding II LLC as Issuer and The Bank of New York as Trustee. (incorporated(incorporated by reference to JCP&L’s Form 8-K filed August 10, 2006, Exhibit 4-2)
  
10-3
Bondable Transition Property Sale Agreement dated as of August 10, 2006 between JCP&L Transition Funding II LLC as Issuer and Jersey Central Power & Light Company as Seller. (incorporated(incorporated by reference to JCP&L’s Form 8-K filed August 10, 2006, Exhibit 10-1, File No. 001-03141)
  
10-4
Bondable Transition Property Service Agreement dated as of August 10, 2006 between JCP&L Transition Funding II LLC as Issuer and Jersey Central Power & Light Company as Servicer. (incorporated(incorporated by reference to JCP&L’s Form 8-K filed August 10, 2006, Exhibit 10-2, File No. 001-03141)
  
10-5
Administration Agreement dated as of August 10, 2006 between JCP&L Transition Funding II LLC as Issuer and FirstEnergy Service Company as Administrator. (incorporated(incorporated by reference to JCP&L’s Form 8-K filed August 10, 2006, Exhibit 10-3, File No. 001-03141)
10-6Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power Company, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein. (incorporated by reference to FE's Form 10-Q filed August 2, 2011, Exhibit 10.1, File No. 333-21011)
  
(A) 12-6Consolidated ratios of earnings to fixed charges.
  
(A) 23-5Consent of Independent Registered Public Accounting Firm
 
(A) 31-1Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
  
(A) 31-2Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
  
(A) 32Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. §1350.
  
(A)Provided herein electronic format as an exhibit.

3. Exhibits – Met-Ed

3. Exhibits — Met-Ed
Exhibit
Number
3-1
Amended and Restated Articles of Incorporation of Metropolitan Edison Company, effective December 19, 2007. (incorporated(incorporated by reference to Met-Ed’s Form 10-K filed February 29, 2008, Exhibit 3.9, File No. 001-00446)
  
3-2
Amended and Restated Bylaws of Metropolitan Edison Company, dated December 14, 2007. (incorporated(incorporated by reference to Met-Ed’s Form 10-K filed February 29, 2008, Exhibit 3.10, File No. 001-00446)


305
289



Exhibit
Number
4-1Indenture of Metropolitan Edison Company, dated November 1, 1944, between Metropolitan Edison Company and United States Trust Company of New York, Successor Trustee, as amended and supplemented by fourteen supplemental indentures dated February 1, 1947 through May 1, 1960. (Metropolitan Edison Company’s Instruments of Indebtedness Nos. 1 to 14 inclusive, and 16, incorporated by reference to Amendment No. 1 to 1959 Annual Report of GPU, Inc. on Form U5S, File Nos. 30-126 and 1-3292)
  
4-1(a)
Supplemental Indenture of Metropolitan Edison Company, dated December 1, 1962. (incorporated(incorporated by reference to Registration No. 2-59678, Exhibit 2-E(1))
4-1(b)
Supplemental Indenture of Metropolitan Edison Company, dated March 20, 1964. (incorporated(incorporated by reference to Registration No. 2-59678, Exhibit 2-E(2))
4-1(c)
Supplemental Indenture of Metropolitan Edison Company, dated July 1, 1965. (incorporated(incorporated by reference to Registration No. 2-59678, Exhibit 2-E(3))
4-1(d)
Supplemental Indenture of Metropolitan Edison Company, dated June 1, 1966. (incorporated(incorporated by reference to Registration No. 2-24883, Exhibit 2-B-4))
4-1(e)
Supplemental Indenture of Metropolitan Edison Company, dated March 22, 1968. (incorporated(incorporated by reference to Registration No. 2-29644, Exhibit 4-C-5)
4-1(f)
Supplemental Indenture of Metropolitan Edison Company, dated September 1, 1968. (incorporated(incorporated by reference to Registration No. 2-59678, Exhibit 2-E(6))
4-1(g)
Supplemental Indenture of Metropolitan Edison Company, dated August 1, 1969. (incorporated(incorporated by reference to Registration No. 2-59678, Exhibit 2-E(7))
4-1(h)
Supplemental Indenture of Metropolitan Edison Company, dated November 1, 1971. (incorporated(incorporated by reference to Registration No. 2-59678, Exhibit 2-E(8))
4-1(i)
Supplemental Indenture of Metropolitan Edison Company, dated May 1, 1972. (incorporated(incorporated by reference to Registration No. 2-59678, Exhibit 2-E(9))
4-1(j)
Supplemental Indenture of Metropolitan Edison Company, dated December 1, 1973. (incorporated(incorporated by reference to Registration No. 2-59678, Exhibit 2-E(10))
4-1(k)
Supplemental Indenture of Metropolitan Edison Company, dated October 30, 1974. (incorporated(incorporated by reference to Registration No. 2-59678, Exhibit 2-E(11))
4-1(l)
Supplemental Indenture of Metropolitan Edison Company, dated October 31, 1974. (incorporated(incorporated by reference to Registration No. 2-59678, Exhibit 2-E(12))
4-1(m)
Supplemental Indenture of Metropolitan Edison Company, dated March 20, 1975. (incorporated(incorporated by reference to Registration No. 2-59678, Exhibit 2-E(13))
4-1(n)
Supplemental Indenture of Metropolitan Edison Company, dated September 25, 1975. (incorporated(incorporated by reference to Registration No. 2-59678, Exhibit 2-E(15))
4-1(o)
Supplemental Indenture of Metropolitan Edison Company, dated January 12, 1976. (incorporated(incorporated by reference to Registration No. 2-59678, Exhibit 2-E(16))
4-1(p)
Supplemental Indenture of Metropolitan Edison Company, dated March 1, 1976. (incorporated(incorporated by reference to Registration No. 2-59678, Exhibit 2-E(17))
4-1(q)
Supplemental Indenture of Metropolitan Edison Company, dated September 28, 1977. (incorporated(incorporated by reference to Registration No. 2-62212, Exhibit 2-E(18))
4-1(r)
Supplemental Indenture of Metropolitan Edison Company, dated January 1, 1978. (incorporated(incorporated by reference to Registration No. 2-62212, Exhibit 2-E(19))
4-1(s)
Supplemental Indenture of Metropolitan Edison Company, dated September 1, 1978. (incorporated(incorporated by reference to Registration No. 33-48937, Exhibit 4-A(19))
4-1(t)
Supplemental Indenture of Metropolitan Edison Company, dated June 1, 1979. (incorporated(incorporated by reference to Registration No. 33-48937, Exhibit 4-A(20))
4-1(u)
Supplemental Indenture of Metropolitan Edison Company, dated January 1, 1980. (incorporated(incorporated by reference to Registration No. 33-48937, Exhibit 4-A(21))


306



Exhibit
Number
4-1(v)
Supplemental Indenture of Metropolitan Edison Company, dated September 1, 1981. (incorporated(incorporated by reference to Registration No. 33-48937, Exhibit 4-A(22))
4-1(w)
Supplemental Indenture of Metropolitan Edison Company, dated September 10, 1981. (incorporated(incorporated by reference to Registration No. 33-48937, Exhibit 4-A(23))
4-1(x)
Supplemental Indenture of Metropolitan Edison Company, dated December 1, 1982. (incorporated(incorporated by reference to Registration No. 33-48937, Exhibit 4-A(24))
4-1(y)
Supplemental Indenture of Metropolitan Edison Company, dated September 1, 1983. (incorporated(incorporated by reference to Registration No. 33-48937, Exhibit 4-A(25))
4-1(z)
Supplemental Indenture of Metropolitan Edison Company, dated September 1, 1984. (incorporated(incorporated by reference to Registration No. 33-48937, Exhibit 4-A(26))
4-1(aa)
Supplemental Indenture of Metropolitan Edison Company, dated March 1, 1985. (incorporated(incorporated by reference to Registration No. 33-48937, Exhibit 4-A(27))
4-1(bb)Supplemental Indenture of Metropolitan Edison Company, dated September 1, 1985. (Registration No. 33-48937, Exhibit 4-A(28))

290
4-1(cc)
Supplemental Indenture of Metropolitan Edison Company, dated June 1, 1988. (incorporated(incorporated by reference to Registration No. 33-48937, Exhibit 4-A(29))
4-1(dd)
Supplemental Indenture of Metropolitan Edison Company, dated April 1, 1990. (incorporated(incorporated by reference to Registration No. 33-48937, Exhibit 4-A(30))
4-1(ee)
Amendment dated May 22, 1990 to Supplemental Indenture of Metropolitan Edison Company, dated April 1, 1990. (incorporated(incorporated by reference to Registration No. 33-48937, Exhibit 4-A(31))
4-1(ff)
Supplemental Indenture of Metropolitan Edison Company, dated September 1, 1992. (incorporated(incorporated by reference to Registration No. 33-48937, Exhibit 4-A(32)(a))
4-1(gg)
Supplemental Indenture of Metropolitan Edison Company, dated December 1, 1993. (incorporated(incorporated by reference to GPU, Inc.’s Form U5S filed May 2, 1994, Exhibit C-58, File No. 30-126)
4-1(hh)
Supplemental Indenture of Metropolitan Edison Company, dated July 15, 1995. (incorporated(incorporated by reference to 1995 Form 10-K, Exhibit 4-B-35, File No. 1-446)
4-1(ii)
Supplemental Indenture of Metropolitan Edison Company, dated August 15, 1996. (incorporated(incorporated by reference to Met-Ed’s Form 10-K filed March 10, 1997, Exhibit 4-B-35, File No. 033-51001)
4-1(jj)
Supplemental Indenture of Metropolitan Edison Company, dated May 1, 1997. (incorporated(incorporated by reference to Met-Ed’s Form 10-K filed March 13, 1998, Exhibit 4-B-36, File No. 033-51001)
4-1(kk)
Supplemental Indenture of Metropolitan Edison Company, dated July 1, 1999. (incorporated(incorporated by reference to Met-Ed’s Form 10-K filed March 20, 2000, Exhibit 4-B-38, File No. 033-51001)
4-1(ll)
Supplemental Indenture of Metropolitan Edison Company, dated May 1, 2001. (incorporated(incorporated by reference to Met-Ed’s Form 10-K filed April 1, 2002, Exhibit 4-5, File No. 033-51001)
4-1(mm)
Supplemental Indenture of Metropolitan Edison Company, dated March 1, 2003. (incorporated(incorporated by reference to Met-Ed’s Form 10-K filed March 15, 2004, Exhibit 4-10, File No. 033-51001)
  
4-2Senior Note Indenture between Metropolitan Edison Company and United States Trust Company of New York, dated July 1, 1999. (incorporated by reference to GPU, Inc.’s Form U5S filed May 2, 2002, Exhibit C-154, File No. 001-06047)
  
4-2(a)
Form of Metropolitan Edison Company 7.70% Senior Notes due 2019. (incorporated(incorporated by reference to Met-Ed’s Form 8-K filed January 21, 2009, Exhibit 4.1, File No. 001-00446)
10-1Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power Company, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein. (incorporated by reference to FE's Form 10-Q filed August 2, 2011, Exhibit 10.1, File No. 333-21011)


307



Exhibit
Number
  
(A) 12-7Consolidated ratios of earnings to fixed charges.
  
(A) 23-6Consent of Independent Registered Public Accounting Firm
 
(A) 31-1Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
  
(A) 31-2Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
  
(A) 32Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. §1350.
  
(A)Provided herein electronic format as an exhibit.

3. Exhibits – Penelec

3. Exhibits — Penelec
Exhibit
Number
3-1
Amended and Restated Articles of Incorporation of Pennsylvania Electric Company, effective December 19, 2007. (incorporated(incorporated by reference to Penelec’s Form 10-K filed February 29, 2008, Exhibit 3.11, File No. 001-03522)
  
3-2
Amended and Restated Bylaws of Pennsylvania Electric Company, dated December 14, 2007. (incorporated(incorporated by reference to Penelec’s Form 10-K filed February 29, 2008, Exhibit 3.12, File No. 001-03522)
  
4-1Mortgage and Deed of Trust of Pennsylvania Electric Company, dated January 1, 1942, between Pennsylvania Electric Company and United States Trust Company of New York, Successor Trustee, and indentures supplemental thereto dated March 7, 1942 through May 1, 1960 –— (Pennsylvania Electric Company’s Instruments of Indebtedness Nos. 1-20, inclusive, incorporated by reference to Amendment No. 1 to 1959 Annual Report of GPU on Form U5S, File Nos. 30-126 and 1-3292)

291
4-1(a)Supplemental Indentures to Mortgage and Deed of Trust of Pennsylvania Electric Company, dated May 1, 1961 through December 1, 1977. (incorporated by reference to Registration No. 2-61502, Exhibit 2-D(1) to 2-D(19))
4-1(b)Supplemental Indenture of Pennsylvania Electric Company, dated June 1, 1978. (incorporated by reference to Registration No. 33-49669, Exhibit 4-A(2))
4-1(c)Supplemental Indenture of Pennsylvania Electric Company dated June 1, 1979. (incorporated by reference to Registration No. 33-49669, Exhibit 4-A(3))
4-1(d)Supplemental Indenture of Pennsylvania Electric Company, dated September 1, 1984. (incorporated by reference to Registration No. 33-49669, Exhibit 4-A(4))
4-1(e)Supplemental Indenture of Pennsylvania Electric Company, dated December 1, 1985. (incorporated by reference to Registration No. 33-49669, Exhibit 4-A(5))
4-1(f)Supplemental Indenture of Pennsylvania Electric Company, dated December 1, 1986. (incorporated by reference to Registration No. 33-49669, Exhibit 4-A(6))
4-1(g)Supplemental Indenture of Pennsylvania Electric Company, dated May 1, 1989. (incorporated by reference to Registration No. 33-49669, Exhibit 4-A(7))
4-1(h)Supplemental Indenture of Pennsylvania Electric Company, dated December 1, 1990. (incorporated by reference to Registration No. 33-45312, Exhibit 4-A(8))
4-1(i)Supplemental Indenture of Pennsylvania Electric Company, dated March 1, 1992. (incorporated by reference to Registration No. 33-45312, Exhibit 4-A(9))
4-1(j)Supplemental Indenture of Pennsylvania Electric Company, dated June 1, 1993. (incorporated by reference to GPU, Inc.’s Form U5S filed May 2, 1994, Exhibit C-73, File No. 001-06047)
4-1(k)Supplemental Indenture of Pennsylvania Electric Company, dated November 1, 1995. (incorporated by reference to 1995 Form 10-K, Exhibit 4-C-11, File No. 1-3522)
4-1(l)Supplemental Indenture of Pennsylvania Electric Company, dated August 15, 1996. (incorporated by reference to Penelec’s Form 10-K filed March 10, 1997, Exhibit 4-C-12, File No. 001-03522)


308


3. Exhibits — Penelec
Exhibit
Number
4-1(m)Supplemental Indenture of Pennsylvania Electric Company, dated May 1, 2001. (incorporated by reference to Penelec’s Form 10-K filed April 1, 2002, Exhibit 4-C-16, File No. 001-03522)
  
4-2Senior Note Indenture between Pennsylvania Electric Company and United States Trust Company of New York, dated April 1, 1999. (incorporated by reference to Penelec’s Form 10-K filed March 20, 2000, Exhibit 4-C-13, File No. 001-03522)
4-2(a)Form of Pennsylvania Electric Company 6.05% Senior Notes due 2017. (incorporated by reference to Penelec’s Form 8-K filed August 31, 2007, Exhibit 4.1, File No. 001-03522)
4-2(b)Company Order, dated as of September 30, 2009 establishing the terms of the 5.20% Senior Notes due 2020 and 6.15% Senior Notes due 2038 (incorporated by reference to Penelec'sPenelec’s Form 8-K filed October 6, 2009, Exhibit 4.1, File No. 001-03522)
4-2(c)Supplemental Indenture No. 2, dated as of October 1, 2009, to the Indenture dated as of April 1, 2009, as amended, between Pennsylvania Electric Company and The Bank of New York Mellon, as successor trustee (incorporated by reference to Penelec'sPenelec’s Form 8-K filed October 6, 2009, Exhibit 4.4, File No. 001-03522)
4-2(d)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'sPenelec’s Form 8-K filed on October 6, 2009, Exhibit 4.5, File No. 001-03522)
  
10-1Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power Company, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein. (incorporated by reference to FE's Form 10-Q filed August 2, 2011, Exhibit 10.1, File No. 333-21011)
(A) 12-8Consolidated ratios of earnings to fixed charges.
  
(A) 23-7Consent of Independent Registered Public Accounting Firm.
 
(A) 31-1Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
  
(A) 31-2Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
  

292
(A) 32Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. §1350.
  
(A)Provided here in electronic format as an exhibit.



3. Exhibits - Common Exhibits for FES, Met-Ed and Penelec309


10-13. Exhibits — Common Exhibits for FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec
Notice of Termination Tolling Agreement dated as of April 7, 2006; Restated Partial Requirements Agreement, dated January 1, 2003, by and among, Metropolitan Edison Company, Pennsylvania Electric Company, The Waverly Electric Power and Light Company and FirstEnergy Solutions Corp., as amended by a First Amendment to Restated Requirements Agreement, dated August 29, 2003 and by a Second Amendment to Restated Requirements Agreement, dated June 8, 2004 (“Partial Requirements Agreement”). (incorporated by reference to Met-Ed’s Form 10-Q filed May 9, 2006,
Exhibit 10-5, File No. 001-00446)
Number
  
10-2(A) 18Third Restated Partial Requirements Agreement, among Metropolitan Edison Company, Pennsylvania Electric Company, a Pennsylvania corporation, The Waverly Electric PowerPricewaterhouseCoopers LLP Preferability Letter Related to Change in Accounting for Pensions and Light Company and FirstEnergy Solutions Corp., dated November 1, 2008. (incorporated by reference to Met-Ed’s Form 10-Q filed November 7, 2008, Exhibit 10-2, File No. 001-00446)Other Postretirement Benefits.
  
10-3101*Fourth Restated Partial Requirements Agreement, among Metropolitan Edison Company, Pennsylvania Electric Company, a Pennsylvania corporation, The Waverly Electric Power and Light Company and FirstEnergy Solutions Corp., dated November 1, 2008. (incorporated by reference to Met-Ed’sfollowing materials from the Annual Reports on Form 10-Q filed November 9, 2009, Exhibit 10.2, File No. 001-00446)

3. Exhibits - Common Exhibits for FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec

10-1
$2,750,000,000 Credit Agreement dated as10-K of August 24, 2006 among FirstEnergy Corp., FirstEnergy Solutions Corp., American Transmission Systems, Inc., Ohio Edison Company, Pennsylvania Power Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company, and Pennsylvania Electric Company, for the period ended December 31, 2011, 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 Borrowers, the banks party thereto, the fronting banks party theretoblocks of text and the swing line lenders party thereto. (incorporated by reference to FE’s Form 8-K filed August 24, 2006, Exhibit 10-1, File No. 333-21011)
(v) document and entity information.
  
10-2*
Consent
Users of this data are advised in accordance with Rule 406T of Regulation S-T promulgated by the Securities and AmendmentExchange Commission that the Interactive Data Files 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 are 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, are deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to $2,750,000,000 Credit Agreement dated November 2, 2007. (incorporated by reference to FE’s Form 10-K filed February 29, 2008, Exhibit 10-2, File No. 333-21011)liability under these sections.
(A)Provided herein in electronic format as an exhibit.


310
293


Report of Independent Registered Public Accounting FirmSCHEDULE II
FIRSTENERGY CORP.
onCONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
Financial Statement ScheduleFOR THE YEARS ENDED DECEMBER 31, 2011, 2010 AND 2009
    Additions    
Description Beginning Balance Charged to Income Charged to Other Accounts Deductions Ending Balance
  (In thousands)
Year Ended December 31, 2011:          
Accumulated provision for uncollectible accounts — customers $36,272
 $78,521
 $38,042
(1) 
$115,532
(2) 
$37,303
— other $8,252
 $663
 $927
(1) 
$6,395
(2) 
$3,447
Loss carryforward tax valuation reserve $26,051
 $(18,933) $27,118
 $—
 $34,236
           
Year Ended December 31, 2010:          
Accumulated provision for uncollectible accounts — customers $33,431
 $59,750
 $37,813
(1) 
$94,722
(2) 
$36,272
— other $6,969
 $2,687
 $1,037
(1) 
$2,441
(2) 
$8,252
Loss carryforward tax valuation reserve $22,600
 $3,451
 $—
 $—
 $26,051
           
Year Ended December 31, 2009:          
Accumulated provision for uncollectible accounts — customers $27,847
 $67,503
 $32,975
(1) 
$94,894
(2) 
$33,431
— other $9,167
 $(405) $10,457
(1) 
$12,250
(2) 
$6,969
Loss carryforward tax valuation reserve $17,151
 $5,449
 $—
 $—
 $22,600
(1)
Represents recoveries and reinstatements of accounts previously written off.
(2)
Represents the write-off of accounts considered to be uncollectible.



311


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

Our audits of the consolidated financial statements and of the effectiveness of internal control over financial reporting referred to in our report dated February 18, 2010 also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.


PricewaterhouseCoopers LLP
Cleveland, Ohio
February 18, 2010

294

Report of Independent Registered Public Accounting Firm
on
Financial Statement Schedule




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

Our audits of the consolidated financial statements referred to in our report dated February 18, 2010 also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.


PricewaterhouseCoopers LLP
Cleveland, Ohio
February 18, 2010

295

Report of Independent Registered Public Accounting Firm
on
Financial Statement Schedule




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

Our audits of the consolidated financial statements referred to in our report dated February 18, 2010 also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.


PricewaterhouseCoopers LLP
Cleveland, Ohio
February 18, 2010

296

Report of Independent Registered Public Accounting Firm
on
Financial Statement Schedule




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

Our audits of the consolidated financial statements referred to in our report dated February 18, 2010 also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.


PricewaterhouseCoopers LLP
Cleveland, Ohio
February 18, 2010

297

Report of Independent Registered Public Accounting Firm
on
Financial Statement Schedule




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

Our audits of the consolidated financial statements referred to in our report dated February 18, 2010 also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.


PricewaterhouseCoopers LLP
Cleveland, Ohio
February 18, 2010

298

Report of Independent Registered Public Accounting Firm
on
Financial Statement Schedule




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

Our audits of the consolidated financial statements referred to in our report dated February 18, 2010 also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.


PricewaterhouseCoopers LLP
Cleveland, Ohio
February 18, 2010

299

Report of Independent Registered Public Accounting Firm
on
Financial Statement Schedule




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

Our audits of the consolidated financial statements referred to in our report dated February 18, 2010 also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.


PricewaterhouseCoopers LLP
Cleveland, Ohio
February 18, 2010

300

Report of Independent Registered Public Accounting Firm
on
Financial Statement Schedule




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

Our audits of the consolidated financial statements referred to in our report dated February 18, 2010 also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.


PricewaterhouseCoopers LLP
Cleveland, Ohio
February 18, 2010

301

SCHEDULE II
FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2011, 2010 AND 2009
    Additions    
Description Beginning Balance Charged to Income Charged to Other Accounts Deductions Ending Balance
  (In thousands)
Year Ended December 31, 2011:          
Accumulated provision for uncollectible accounts — customers $16,591
 $11,250
 $—
(1) 
$11,400
(2) 
$16,441
— other $6,765
 $22
 $4
(1) 
$4,291
(2) 
$2,500
Loss carryforward tax valuation reserve $9,290
 $2,360
 $—
 $—
 $11,650
           
Year Ended December 31, 2010:          
Accumulated provision for uncollectible accounts — customers $12,041
 $9,397
 $—
(1) 
$4,847
(2) 
$16,591
— other $6,702
 $64
 $—
(1) 
$1
(2) 
$6,765
Loss carryforward tax valuation reserve $7,189
 $2,101
 $—
 $—
 $9,290
           
Year Ended December 31, 2009:          
Accumulated provision for uncollectible accounts — customers $5,899
 $7,745
 $—
(1) 
$1,603
(2) 
$12,041
— other $6,815
 $(161) $57
(1) 
$9
(2) 
$6,702
Loss carryforward tax valuation reserve $4,028
 $3,161
 $—
 $—
 $7,189
(1)
Represents recoveries and reinstatements of accounts previously written off.
(2)
Represents the write-off of accounts considered to be uncollectible.


FIRSTENERGY CORP. 
  
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS 
FOR THE YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007 
                
     Additions       
        Charged       
  Beginning  Charged  to Other     Ending 
Description Balance  to Income  Accounts  Deductions  Balance 
  (In thousands) 
Year Ended December 31, 2009:               
                
Accumulated provision for               
uncollectible accounts – customers $27,847  $67,503  $32,975(a) $94,894(b) $33,431 
– other $9,167  $(405) $10,457(a) $12,250(b) $6,969 
                     
Loss carryforward                    
tax valuation reserve $27,294  $(1,091) $(4,921) $-  $21,282 
                     
                     
Year Ended December 31, 2008:                    
                     
Accumulated provision for                    
uncollectible accounts – customers $35,567  $48,297  $31,308(a) $87,325(b) $27,847 
– other $21,924  $11,339  $3,189(a) $27,285(b) $9,167 
                     
Loss carryforward                    
tax valuation reserve $30,616  $1,435  $(4,757) $-  $27,294 
                     
                     
Year Ended December 31, 2007:                    
                     
Accumulated provision for                    
uncollectible accounts – customers $43,214  $53,522  $50,165(a) $111,334(b) $35,567 
– other $23,964  $4,933  $406(a) $7,379(b) $21,924 
                     
Loss carryforward                    
tax valuation reserve $415,531  $8,819  $(393,734) $-  $30,616 
                     
                     
                     
(a) Represents recoveries and reinstatements of accounts previously written off. 
(b) Represents the write-off of accounts considered to be uncollectible. 
312

302


SCHEDULE II
OHIO EDISON COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2011, 2010 AND 2009
    Additions    
Description Beginning Balance Charged to Income Charged to Other Accounts Deductions Ending Balance
  (In thousands)
Year Ended December 31, 2011:          
Accumulated provision for uncollectible accounts — customers $4,086
 $8,936
 $9,660
(1) 
$18,806
(2) 
$3,876
— other $6
 $39
 $208
(1) 
$244
(2) 
$9
Year Ended December 31, 2010:          
Accumulated provision for uncollectible accounts — customers $5,119
 $6,588
 $11,074
(1) 
$18,695
(2) 
$4,086
— other $18
 $5
 $180
(1) 
$197
(2) 
$6
Year Ended December 31, 2009:          
Accumulated provision for uncollectible accounts — customers $6,065
 $16,230
 $11,252
(1) 
$28,428
(2) 
$5,119
— other $7
 $17
 $326
(1) 
$332
(2) 
$18
(1)
Represents recoveries and reinstatements of accounts previously written off.
(2)
Represents the write-off of accounts considered to be uncollectible.


FIRSTENERGY SOLUTIONS CORP. 
  
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS 
FOR THE YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007 
                
     Additions       
        Charged       
  Beginning  Charged  to Other     Ending 
Description Balance  to Income  Accounts  Deductions  Balance 
  (In thousands) 
Year Ended December 31, 2009:               
                
Accumulated provision for               
uncollectible accounts – customers $5,899  $6,142  $-(a) $-(b) $12,041 
– other $6,815  $(161) $57(a) $9(b) $6,702 
                     
                     
Year Ended December 31, 2008:                    
                     
Accumulated provision for                    
uncollectible accounts – customers $8,072  $(2,174) $110(a) $109(b) $5,899 
– other $9  $4,374  $2,541(a) $109(b) $6,815 
                     
                     
Year Ended December 31, 2007:                    
                     
Accumulated provision for                    
uncollectible accounts – customers $7,938  $94  $532(a) $492(b) $8,072 
– other $5,593  $9  $-(a) $5,593(b) $9 
                     
                     
                     
                     
(a) Represents recoveries and reinstatements of accounts previously written off. 
(b) Represents the write-off of accounts considered to be uncollectible. 
313

303


SCHEDULE II
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
OHIO EDISON COMPANY 
  
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS 
FOR THE YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007 
                
     Additions       
        Charged       
  Beginning  Charged  to Other     Ending 
Description Balance  to Income  Accounts  Deductions  Balance 
  (In thousands) 
Year Ended December 31, 2009:               
                
Accumulated provision for               
uncollectible accounts – customers $6,065  $16,230  $11,252(a) $28,428(b) $5,119 
– other $7  $17  $326(a) $332(b) $18 
                     
                     
Year Ended December 31, 2008:                    
                     
Accumulated provision for                    
uncollectible accounts – customers $8,032  $12,179  $10,027(a) $24,173(b) $6,065 
– other $5,639  $16,618  $394(a) $22,644(b) $7 
                     
                     
Year Ended December 31, 2007:                    
                     
Accumulated provision for                    
uncollectible accounts – customers $15,033  $10,513  $30,234(a) $47,748(b) $8,032 
– other $1,985  $4,117  $(240)(a) $223(b) $5,639 
                     
                     
                     
                     
(a) Represents recoveries and reinstatements of accounts previously written off. 
(b) Represents the write-off of accounts considered to be uncollectible. 
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2011, 2010 AND 2009
    Additions    
Description Beginning Balance Charged to Income Charged to Other Accounts Deductions Ending Balance
  (In thousands)
Year Ended December 31, 2011:          
Accumulated provision for uncollectible accounts — customers $4,589
 $5,134
 $6,752
(1) 
$13,542
(2) 
$2,933
— other $1
 $105
 $10
(1) 
$46
(2) 
$70
Year Ended December 31, 2010:          
Accumulated provision for uncollectible accounts — customers $5,239
 $14,716
 $11,151
(1) 
$26,517
(2) 
$4,589
— other $21
 $33
 $50
(1) 
$103
(2) 
$1
Year Ended December 31, 2009:          
Accumulated provision for uncollectible accounts — customers $5,916
 $16,764
 $8,942
(1) 
$26,383
(2) 
$5,239
— other $11
 $50
 $51
(1) 
$91
(2) 
$21
(1)
Represents recoveries and reinstatements of accounts previously written off.
(2)
Represents the write-off of accounts considered to be uncollectible.


314
304


SCHEDULE II
THE TOLEDO EDISON COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2011, 2010 AND 2009
    Additions    
Description Beginning Balance Charged to Income Charged to Other Accounts Deductions Ending Balance
  (In thousands)
Year Ended December 31, 2011:          
Accumulated provision for uncollectible accounts — customers $1
 $4,707
 $3,448
(1) 
$6,689
(2) 
$1,467
— other $330
 $(65) $1
(1) 
$2
(2) 
$264
Year Ended December 31, 2010:          
Accumulated provision for uncollectible accounts — customers $—
 $2
 $—
(1) 
$1
(2) 
$1
— other 208
 127
 13
(1) 
18
(2) 
330
Year Ended December 31, 2009:          
Accumulated provision for uncollectible accounts — other $203
 $(115) $165
(1) 
$45
(2) 
$208
(1)
Represents recoveries and reinstatements of accounts previously written off.
(2)
Represents the write-off of accounts considered to be uncollectible.


THE CLEVELAND ELECTRIC ILLUMINATING COMPANY 
  
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS 
FOR THE YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007 
                
     Additions       
        Charged       
  Beginning  Charged  to Other     Ending 
Description Balance  to Income  Accounts  Deductions  Balance 
  (In thousands) 
Year Ended December 31, 2009:               
                
Accumulated provision for               
uncollectible accounts – customers $5,916  $16,764  $8,942(a) $26,383(b) $5,239 
– other $11  $50  $51(a) $91(b) $21 
                     
                     
Year Ended December 31, 2008:                    
                     
Accumulated provision for                    
uncollectible accounts – customers $7,540  $11,323  $9,179(a) $22,126(b) $5,916 
– other $433  $(183) $30(a) $269(b) $11 
                     
                     
Year Ended December 31, 2007:                    
                     
Accumulated provision for                    
uncollectible accounts – customers $6,783  $17,998  $7,842(a) $25,083(b) $7,540 
– other $-  $431  $124(a) $122(b) $433 
                     
                     
                     
                     
(a) Represents recoveries and reinstatements of accounts previously written off. 
(b) Represents the write-off of accounts considered to be uncollectible. 
315


305

SCHEDULE II
JERSEY CENTRAL POWER & LIGHT COMPANY
THE TOLEDO EDISON COMPANY 
  
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS 
FOR THE YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007 
                
     Additions       
        Charged       
  Beginning  Charged  to Other     Ending 
Description Balance  to Income  Accounts  Deductions  Balance 
  (In thousands) 
Year Ended December 31, 2009:               
                
Accumulated provision for               
uncollectible accounts $203  $(115) $165(a) $45(b) $208 
                     
Year Ended December 31, 2008:                    
                     
Accumulated provision for                    
uncollectible accounts $615  $(247) $121(a) $286(b) $203 
                     
Year Ended December 31, 2007:                    
                     
Accumulated provision for                    
uncollectible accounts $430  $361  $13(a) $189(b) $615 
                     
                     
                     
                     
(a) Represents recoveries and reinstatements of accounts previously written off. 
(b) Represents the write-off of accounts considered to be uncollectible. 
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2011, 2010 AND 2009
    Additions    
Description Beginning Balance Charged to Income Charged to Other Accounts Deductions Ending Balance
  (In thousands)
Year Ended December 31, 2011:          
Accumulated provision for uncollectible accounts — customers $3,769
 $11,419
 $5,718
(1) 
$17,325
(2) 
$3,581
— other $22
 $(44) $700
(1) 
$678
(2) 
$—
Year Ended December 31, 2010:          
Accumulated provision for uncollectible accounts — customers $3,506
 $12,487
 $5,251
(1) 
$17,475
(2) 
$3,769
— other $—
 $209
 $70
(1) 
$257
(2) 
$22
Year Ended December 31, 2009:   
 
 
 
Accumulated provision for uncollectible accounts — customers $3,230
 $11,519
 $5,424
(1) 
$16,667
(2) 
$3,506
— other $45
 $(37) $380
(1) 
$388
(2) 
$—
(1)
Represents recoveries and reinstatements of accounts previously written off.
(2)
Represents the write-off of accounts considered to be uncollectible.



316
306


SCHEDULE II
METROPOLITAN EDISON COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2011, 2010 AND 2009
    Additions    
Description Beginning Balance Charged to Income Charged to Other Accounts Deductions Ending Balance
  (In thousands)
Year Ended December 31, 2011:          
Accumulated provision for uncollectible accounts — customers $3,868
 $11,569
 $4,701
(1) 
$17,123
(2) 
$3,015
— other $—
 $7
 $3
(1) 
$10
(2) 
$—
Year Ended December 31, 2010:          
Accumulated provision for uncollectible accounts — customers $4,044
 $10,021
 $5,248
(1) 
$15,445
(2) 
$3,868
— other $—
 $14
 $39
(1) 
$53
(2) 
$—
Year Ended December 31, 2009:          
Accumulated provision for uncollectible accounts — customers $3,616
 $9,583
 $3,926
(1) 
$13,081
(2) 
$4,044
— other $—
 $8
 $26
(1) 
$34
(2) 
$—
(1)
Represents recoveries and reinstatements of accounts previously written off.
(2)
Represents the write-off of accounts considered to be uncollectible.


JERSEY CENTRAL POWER & LIGHT COMPANY 
  
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS 
FOR THE YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007 
                
     Additions       
        Charged       
  Beginning  Charged  to Other     Ending 
Description Balance  to Income  Accounts  Deductions  Balance 
  (In thousands) 
Year Ended December 31, 2009:               
                
Accumulated provision for               
uncollectible accounts – customers $3,230  $11,519  $5,424(a) $16,667(b) $3,506 
– other $45  $(37) $380(a) $388(b) $- 
                     
                     
Year Ended December 31, 2008:                    
                     
Accumulated provision for                    
uncollectible accounts – customers $3,691  $10,377  $3,504(a) $14,342(b) $3,230 
– other $-  $44  $24(a) $23(b) $45 
                     
                     
Year Ended December 31, 2007:                    
                     
Accumulated provision for                    
uncollectible accounts – customers $3,524  $8,563  $4,049(a) $12,445(b) $3,691 
– other $-  $-  $-(a) $-(b) $- 
                     
                     
                     
                     
(a) Represents recoveries and reinstatements of accounts previously written off. 
(b) Represents the write-off of accounts considered to be uncollectible. 
317

307


SCHEDULE II
PENNSYLVANIA ELECTRIC COMPANY
METROPOLITAN EDISON COMPANY 
  
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS 
FOR THE YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007 
                
     Additions       
        Charged       
  Beginning  Charged  to Other     Ending 
Description Balance  to Income  Accounts  Deductions  Balance 
  (In thousands) 
Year Ended December 31, 2009:               
                
Accumulated provision for               
uncollectible accounts – customers $3,616  $9,583  $3,926(a) $13,081(b) $4,044 
– other $-  $8  $26(a) $34(b) $- 
                     
                     
Year Ended December 31, 2008:                    
                     
Accumulated provision for                    
uncollectible accounts – customers $4,327  $9,004  $3,729(a) $13,444(b) $3,616 
– other $1  $19  $21(a) $41(b) $- 
                     
                     
Year Ended December 31, 2007:                    
                     
Accumulated provision for                    
uncollectible accounts – customers $4,153  $9,971  $3,548(a) $13,345(b) $4,327 
– other $2  $245  $18(a) $264(b) $1 
                     
                     
                     
                     
(a) Represents recoveries and reinstatements of accounts previously written off. 
(b) Represents the write-off of accounts considered to be uncollectible. 
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2011, 2010 AND 2009
    Additions    
Description Beginning Balance Charged to Income Charged to Other Accounts Deductions Ending Balance
  (In thousands)
Year Ended December 31, 2011:          
Accumulated provision for uncollectible accounts — customers $3,369
 $8,025
 $4,552
(1) 
$13,703
(2) 
$2,243
— other $1
 $2
 $1
(1) 
$2
(2) 
$2
Loss carryforward tax valuation reserve $11,312
 $(4,413) $—
 $—
 $6,899
           
Year Ended December 31, 2010:          
Accumulated provision for uncollectible accounts — customers $3,483
 $6,538
 $5,088
(1) 
$11,740
(2) 
$3,369
— other $3
 $5
 $684
(1) 
$691
(2) 
$1
Loss carryforward tax valuation reserve $9,141
 $2,171
 $—
 $—
 $11,312
           
Year Ended December 31, 2009:          
Accumulated provision for uncollectible accounts — customers $3,121
 $7,264
 $3,431
(1) 
$10,333
(2) 
$3,483
— other $65
 $(57) $7,557
(1) 
$7,562
(2) 
$3
Loss carryforward tax valuation reserve $4,598
 $4,543
 $—
 $—
 $9,141
(1)
Represents recoveries and reinstatements of accounts previously written off.
(2)
Represents the write-off of accounts considered to be uncollectible.



318
308

SCHEDULE II
PENNSYLVANIA ELECTRIC COMPANY 
  
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS 
FOR THE YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007 
                
     Additions       
        Charged       
  Beginning  Charged  to Other     Ending 
Description Balance  to Income  Accounts  Deductions  Balance 
  (In thousands) 
Year Ended December 31, 2009:               
                
Accumulated provision for               
uncollectible accounts – customers $3,121  $7,264  $3,431(a) $10,333(b) $3,483 
– other $65  $(57) $7,557(a) $7,562(b) $3 
                     
                     
Year Ended December 31, 2008:                    
                     
Accumulated provision for                    
uncollectible accounts – customers $3,905  $7,589  $4,758(a) $13,131(b) $3,121 
– other $105  $57  $36(a) $133(b) $65 
                     
                     
Year Ended December 31, 2007:                    
                     
Accumulated provision for                    
uncollectible accounts – customers $3,814  $8,351  $3,958(a) $12,218(b) $3,905 
– other $3  $181  $3(a) $82(b) $105 
                     
                     
                     
                     
(a) Represents recoveries and reinstatements of accounts previously written off. 
(b) Represents the write-off of accounts considered to be uncollectible. 

309

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.




FIRSTENERGY CORP.
 
FIRSTENERGY CORP.

BY:/s/ Anthony J. Alexander 
  
BY: /s/ Anthony J. Alexander
Anthony J. Alexander
 President and Chief Executive Officer
Date: February 28, 2012


Date:  February 18, 2010319

310


SIGNATURES


Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:


/s/ George M. Smart
 
/s/ Anthony J. Alexander
George M. Smart Anthony J. Alexander
Chairman of the Board President and Chief Executive Officer and Director
  and Director (Principal(Principal Executive Officer)
 
   
 
/s/ Mark T. Clark
 
/s/ Harvey L. Wagner
Mark T. Clark Harvey L. Wagner
Executive Vice President and Chief Financial Officer Vice President, Controller and Chief Accounting Officer
Officer (Principal(Principal Financial Officer) Officer (Principal(Principal Accounting Officer)
 
   
 
/s/ Paul T. Addison
 
/s/ Ernest J. Novak, Jr.
Donald T. Misheff
Paul T. Addison Ernest J. Novak, Jr.Donald T. Misheff
Director Director
 
   
 
/s/ Michael J. Anderson
 
/s/ Catherine A. Rein
Ernest J. Novak, Jr.
Michael J. Anderson Catherine A. ReinErnest J. Novak, Jr.
Director Director
 
   
 
/s/ Carol A. Cartwright
 
/s/ Wes M. Taylor
Christopher D. Pappas
Carol A. Cartwright Wes M. TaylorChristopher D. Pappas
Director Director
 
   
 
/s/ William T. Cottle
 
/s/ Jesse T. Williams, Sr.
Catherine A. Rein
William T. Cottle Jesse T. Williams, Sr.Catherine A. Rein
Director Director
 
   
 
/s/ Robert B. Heisler, Jr.
 /s/ Wes M. Taylor 
Robert B. Heisler, Jr. Wes M. Taylor 
Director Director 
/s/ Julia L. Johnson/s/ Jesse T. Williams, Sr.
Julia L. JohnsonJesse T. Williams, Sr.
DirectorDirector
/s/ Ted J. Kleisner
Ted J. Kleisner
Director   




Date: February 18, 201028, 2012


320
311


SIGNATURES




Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

FIRSTENERGY SOLUTIONS CORP.
 BY:/s/ Donald R. Schneider 
  
BY:    /s/ Donald R. Schneider
 Donald R. Schneider
 President


Date: February 18, 2010


28, 2012
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:





/s/ Donald R. Schneider 
/s/ Mark T. Clark
Donald R. Schneider Mark T. Clark
President Executive Vice President and Chief
(Principal Executive Officer) Chief Financial Officer and Director
  (Principal Financial Officer)
 
   
 
/s/ Anthony J. Alexander
 
/s/ Harvey L. Wagner
Anthony J. Alexander Harvey L. Wagner
Director Vice President and Controller
  (Principal Accounting Officer)
 
   
/s/ James H. Lash   
/s/    Gary R. Leidich
James H. Lash		 
Gary R. Leidich  
Director  
 
Date: February 28, 2012


Date:  February 18, 2010321

312


SIGNATURES




Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

OHIO EDISON COMPANY
 BY:/s/ Charles E. Jones 
  
Charles E. Jones BY:    /s/ Richard R. Grigg
 Richard R. Grigg
 President


Date: February 18, 2010


28, 2012
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:





/s/ Anthony J. Alexander 
/s/ Richard R. Grigg
Charles E. Jones
Anthony J. Alexander Richard R. GriggCharles E. Jones
Director President and Director
  (Principal Executive Officer)
 
   
 
/s/ Mark T. Clark
 
/s/ Harvey L. Wagner
Mark T. Clark Harvey L. Wagner
Executive Vice President and Chief Vice President and Controller
Financial Officer and Director (Principal Accounting Officer)
(Principal Financial Officer)  
Date: February 28, 2012


Date:  February 18, 2010322

313


SIGNATURES




Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 
THE CLEVELAND ELECTRIC
ILLUMINATING COMPANY
 BY:/s/ Charles E. Jones 
  
Charles E. Jones BY:     /s/ Richard R. Grigg
 Richard R. Grigg
 President



Date: February 18, 2010


28, 2012
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:





/s/ Anthony J. Alexander 
/s/ Richard R. Grigg
Charles E. Jones
Anthony J. Alexander Richard R. GriggCharles E. Jones
Director President and Director
  (Principal Executive Officer)
 
   
 
/s/ Mark T. Clark
 
/s/ Harvey L. Wagner
Mark T. Clark Harvey L. Wagner
Executive Vice President and Chief Vice President and Controller
Financial Officer and Director (Principal Accounting Officer)
(Principal Financial Officer)  
Date: February 28, 2012


Date:  February 18, 2010323

314


SIGNATURES




Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


THE TOLEDO EDISON COMPANY
 BY:/s/ Charles E. Jones 
  
Charles E. Jones BY:    /s/ Richard R. Grigg
 Richard R. Grigg
 President


Date: February 18, 2010


28, 2012
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:





/s/ Anthony J. Alexander 
/s/ Richard R. Grigg
Charles E. Jones
Anthony J. Alexander Richard R. GriggCharles E. Jones
Director President and Director
  (Principal Executive Officer)
 
   
 
/s/ Mark T. Clark
 
/s/ Harvey L. Wagner
Mark T. Clark Harvey L. Wagner
Executive Vice President and Chief Vice President and Controller
Financial Officer and Director (Principal Accounting Officer)
(Principal Financial Officer)  
Date: February 28, 2012


Date:  February 18, 2010324

315


SIGNATURES



Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


JERSEY CENTRAL POWER & LIGHT COMPANY
 BY:/s/ Donald M. Lynch 
  
BY: /s/     Donald M. Lynch
 Donald M. Lynch
 President


Date: February 18, 2010


28, 2012
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:





/s/ Donald M. Lynch 
/s/ Kevin R. Burgess
K. Jon Taylor
Donald M. Lynch Kevin R. BurgessK. Jon Taylor
President and Director
Controller
(Principal Executive Officer) 
Controller
(Principal Financial and Accounting Officer)
 
   
/s/ Charles E. Jones /s/ Gelorma E. Persson
Charles E. JonesGelorma E. Persson
DirectorDirector 
   
/s/    Richard R. Grigg
/s/   Gelorma E. Persson
Richard R. GriggGelorma E. Persson
DirectorDirector
 
/s/ Mark A. Julian 
/s/    Charles E. Jones
/s/ Jesse T. Williams, Sr.
Charles E. JonesJesse T. Williams, Sr.
DirectorDirector
/s/    Mark A. Julian
 
Mark A. Julian Jesse T. Williams, Sr. 
Director Director 
Date: February 28, 2012


Date:  February 18, 2010325

316


SIGNATURES




Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

METROPOLITAN EDISON COMPANY
 BY:/s/ Charles E. Jones 
  
Charles E. Jones BY:    /s/ Richard R. Grigg
 Richard R. Grigg
 President


Date: February 18, 2010


28, 2012
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:



/s/ Richard R. GriggAnthony J. Alexander 
/s/ Mark T. Clark
Charles E. Jones
Richard R. GriggAnthony J. Alexander Mark T. ClarkCharles E. Jones
DirectorPresident and Director Executive Vice President and Chief
(Principal Executive Officer)Financial Officer
  (Principal FinancialExecutive Officer)
 
   
 
/s/ Donald A. Brennan
Mark T. Clark		 
/s/ Harvey L. Wagner
Donald A. BrennanMark T. Clark Harvey L. Wagner
RegionalExecutive Vice President and DirectorChief Vice President and Controller
Financial Officer and Director
(Principal Financial Officer)
 (Principal Accounting Officer)
/s/    Randy Scilla
Randy Scilla
Assistant Treasurer and Director 
Date: February 28, 2012


Date:  February 18, 2010326

317


SIGNATURES



Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


PENNSYLVANIA ELECTRIC COMPANY
 BY:/s/ Charles E. Jones 
  
Charles E. Jones BY:    /s/ Richard R. Grigg
 Richard R. Grigg
 President


Date: February 18, 2010

28, 2012
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:



/s/ Richard R. GriggAnthony J. Alexander 
/s/ Mark T. Clark
Charles E. Jones
Richard R. GriggAnthony J. Alexander Mark T. ClarkCharles E. Jones
DirectorPresident and Director Executive Vice President and Chief
(Principal Executive Officer)Financial Officer
  (Principal FinancialExecutive Officer)
 
   
 
/s/ James R. Napier, Jr.
Mark T. Clark		 
/s/ Harvey L. Wagner
James R. Napier, Jr.Mark T. Clark Harvey L. Wagner
RegionalExecutive Vice President and DirectorChief Vice President and Controller
Financial Officer and Director
(Principal Financial Officer)
 (Principal Accounting Officer)
/s/    Randy Scilla
Randy Scilla
Assistant Treasurer and Director 
Date: February 28, 2012



Date:  February 18, 2010
318
327