UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
(Mark One)
   
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2010March 31, 2011
OR
   
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                    to                    
     
Commission Registrant; State of Incorporation; I.R.S. Employer
File Number Address; and Telephone Number Identification No.
 
333-21011 FIRSTENERGY CORP.
(An Ohio Corporation)
76 South Main Street
Akron, OH 44308
Telephone (800)736-3402		 34-1843785
     
000-53742 FIRSTENERGY SOLUTIONS CORP.
(An Ohio Corporation)
c/o FirstEnergy Corp.
76 South Main Street
Akron, OH 44308
Telephone (800)736-3402		 31-1560186
     
1-2578 OHIO EDISON COMPANY
(An Ohio Corporation)
c/o FirstEnergy Corp.
76 South Main Street
Akron, OH 44308
Telephone (800)736-3402		 34-0437786
     
1-2323 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
(An Ohio Corporation)
c/o FirstEnergy Corp.
76 South Main Street
Akron, OH 44308
Telephone (800)736-3402		 34-0150020
     
1-3583 THE TOLEDO EDISON COMPANY
(An Ohio Corporation)
c/o FirstEnergy Corp.
76 South Main Street
Akron, OH 44308
Telephone (800)736-3402		 34-4375005
     
1-3141 JERSEY CENTRAL POWER & LIGHT COMPANY
(A New Jersey Corporation)
c/o FirstEnergy Corp.
76 South Main Street
Akron, OH 44308
Telephone (800)736-3402		 21-0485010
     
1-446 METROPOLITAN EDISON COMPANY
(A Pennsylvania Corporation)
c/o FirstEnergy Corp.
76 South Main Street
Akron, OH 44308
Telephone (800)736-3402		 23-0870160
     
1-3522 PENNSYLVANIA ELECTRIC COMPANY
(A Pennsylvania Corporation)
c/o FirstEnergy Corp.
76 South Main Street
Akron, OH 44308
Telephone (800)736-3402		 25-0718085
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.
   
Yesþ Noo
 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).
   
Yesþ Noo
 FirstEnergy Corp.
   
Yeso Noo
 FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company, and Pennsylvania Electric Company
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
   
Large Accelerated Filerþ
 FirstEnergy Corp.
   
Accelerated Filero
 N/A
   
Non-accelerated Filer (Do not check if a smaller reporting company)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
   
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).
   
Yeso Noþ
 FirstEnergy Corp., FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:
     
  OUTSTANDING 
CLASS AS OF OCTOBER 22, 2010April 29, 2011 
FirstEnergy Corp., $10$.10 par value  304,835,407418,216,437 
FirstEnergy Solutions Corp., no par value  7 
Ohio Edison Company, no par value  60 
The Cleveland Electric Illuminating Company, no par value  67,930,743 
The Toledo Edison Company, $5 par value  29,402,054 
Jersey Central Power & Light Company, $10 par value  13,628,447 
Metropolitan Edison Company, no par value  859,500740,905 
Pennsylvania Electric Company, $20 par value  4,427,577 
FirstEnergy Corp. is the sole holder of FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company common stock.

This combined Form 10-Q is separately filed by FirstEnergy Corp., FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. No registrant makes any representation as to information relating to any other registrant, except that information relating to any of the FirstEnergy subsidiary registrants is also attributed to FirstEnergy Corp.
FirstEnergy Web Site
Each of the registrants’ Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are also made available free of charge on or through FirstEnergy’s Internet web site at www.firstenergycorp.com.
These reports are posted on the web site as soon as reasonably practicable after they are electronically filed with the SEC. Additionally, the registrants routinely post important information on FirstEnergy’s Internet web site and recognize FirstEnergy’s Internet 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 SEC Regulation FD. Information contained on FirstEnergy’s Internet web site shall not be deemed incorporated into, or to be part of, this report.
OMISSION OF CERTAIN INFORMATION
FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.

 

 

Forward-Looking Statements:This Form 10-Q includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements include declarations regarding management’s intents, beliefs and current expectations. These statements typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” “believe,” “estimate” and similar words. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements.
Actual results may differ materially due to:
The speed and nature of increased competition in the electric utility industry and legislative and regulatory changes affecting how generation rates will be determined following the expiration of existing rate plans in Pennsylvania.industry.
The impact of the regulatory process on the pending matters in Ohio, Pennsylvaniathe 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 New Jersey.the uncertainty of the timing and amounts of any related capital expenditures.
Business and regulatory impacts from ATSI’s realignment into PJM.PJM Interconnection, L.L.C.
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.
Replacement power costs being higher than anticipated or inadequately hedged.
The continued ability of FirstEnergy’s regulated utilities to recover regulatory assets or increasedcollect 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.
Theregulations, the potential impacts of the proposed rules promulgated by the EPA on July 6, 2010, in response to the U.S. Court of Appeals’ July 11, 2008 decision requiring revisions to the CAIR rules or any final laws, rules or regulations that may ultimately replace CAIR.CAIR and the effects of the EPA’s recently released MACT proposal to establish certain mercury and other emission standards for electric generating units.
The uncertainty of the timing and amounts of the capital expenditures needed to, among other things, implement the Air Quality Compliance Planthat may arise in connection with any NSR litigation or potential regulatory initiatives or rulemakings (including that such amountsexpenditures could be higher than anticipatedresult in our decision to shut down or thatidle 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.units).
Adverse regulatory or legal decisions and outcomes (including, but not limited to, the revocation of necessary licenses or operating permitspermits) and oversight)oversight by the NRC.NRC, including as a result of the incident at Japan’s Fukushima Daiichi Nuclear Plant.
Ultimate resolution ofAdverse legal decisions and outcomes related to Met-Ed’s and Penelec’s TSC filings withtransmission service charge appeal at the PPUC.Commonwealth Court of Pennsylvania.
The continuing availability of generating units and changes in their ability to operate at or near full capacity.
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 (including employee workforce initiatives).goals.
TheEfforts and our 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 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.capital and overall condition of the capital and credit markets affecting the registrants and other FirstEnergy subsidiaries.
Changes in general economic conditions affecting the registrants.
The state of the capitalregistrants and credit markets affecting the registrants.other FirstEnergy subsidiaries.
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 statecontinuing uncertainty of the national and regional economieseconomy and associated impactsits impact on the registrants’ major industrial and commercial customers.customers and those of other FirstEnergy subsidiaries.
Issues concerning the soundness of financial institutions and counterparties with which the registrants and FirstEnergy’s other subsidiaries do business.
The expected timingIssues arising from the recently completed merger of FirstEnergy and likelihood of completion of the proposed merger with Allegheny Energy, Inc., and the ongoing coordination of their combined operations including the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the proposed merger that could reduce anticipated benefits or cause the parties to abandon the merger, the diversion of management’s time and attention from FirstEnergy’s ongoing business during this time period, the ability to maintain relationships with customers, employees or suppliers, as well as the ability to successfully integrate the businesses and realize cost savings and any other synergies and the risk that the credit ratings of the combined company or its subsidiaries may be different from what the companies expect.
The risks and other factors discussed from time to time in the registrants’ SEC filings, and other similar factors.
Dividends declared from time to time on FirstEnergy’s common stock during any annual period may in aggregate vary from the indicated amount due to circumstances considered by FirstEnergy’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’ business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. A security rating is not a recommendation to buy, sell or hold securities that may be subject to revision or withdrawal at any time by the assigning rating organization. Each rating should be evaluated independently of any other rating. The registrants expressly disclaim any current intention to update any forward-looking statements contained herein as a result of new information, future events or otherwise.

 

 

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

 

i

TABLE OF CONTENTS (Cont’d)
     
  Page 
     
Combined Notes To Consolidated Financial Statements
  26 
     
Item 2. Management’s Discussion and Analysis of Registrant and Subsidiaries
  6378 
     
Management’s Narrative Analysis of Results of Operations
    
     
FirstEnergy Solutions Corp.
  99117 
     
Ohio Edison Company
  102120 
     
The Cleveland Electric Illuminating Company
  104122 
     
The Toledo Edison Company
  106124 
     
Jersey Central Power & Light Company
  108126 
     
Metropolitan Edison Company
  110128 
     
Pennsylvania Electric Company
  112130 
     
Item 3. Quantitative and Qualitative Disclosures About Market Risk
  114132 
     
Item 4. Controls and Procedures — FirstEnergy
  114
Item 4T. Controls and Procedures — FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec
114132 
     
Part II. Other Information
    
     
Item 1. Legal Proceedings
  114133 
     
Item 1A. Risk Factors
  114133 
     
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
  114134 
     
Item 5. Other Information
  114135 
     
Item 6. Exhibits
  115136 
     
 Exhibit 10.1
 Exhibit 10.210.5
 Exhibit 10.310.6
Exhibit 10.7
Exhibit 10.8
Exhibit 10.9
Exhibit 10.10
 Exhibit 12
 Exhibit 31.1
 Exhibit 31.2
 Exhibit 32
 EX-101 INSTANCE DOCUMENT
 EX-101 SCHEMA DOCUMENT
 EX-101 CALCULATION LINKBASE DOCUMENT
 EX-101 LABELS LINKBASE DOCUMENT
 EX-101 PRESENTATION LINKBASE DOCUMENT
 EX-101 DEFINITION LINKBASE DOCUMENT

 

ii

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
AGCAllegheny Generating Company, a generation subsidiary of AE
AlleghenyAllegheny Energy, Inc., together with its consolidated subsidiaries
AVEAllegheny Ventures, Inc.
ATSI American Transmission Systems, Incorporated, which owns and operates transmission facilities
CEI The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
FENOC FirstEnergy Nuclear Operating Company, which operates nuclear generating facilities
FES FirstEnergy Solutions Corp., which provides energy-related products and services
FESC FirstEnergy Service Company, which provides legal, financial and other corporate support services
FEV FirstEnergy Ventures Corp., which invests in certain unregulated enterprises and business ventures
FGCO FirstEnergy Generation Corp., which owns and operates non-nuclear generating facilities
FirstEnergy FirstEnergy Corp., a public utility holding company
Global Rail A joint venture between FirstEnergy Ventures Corp.FEV and WMB Loan Ventures II LLC, that owns coal transportation operations near Roundup, Montana
GPU GPU, Inc., former parent of JCP&L, Met-Ed and Penelec, whichthat merged with FirstEnergy on November 7, 2001
JCP&L Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
Met-Ed Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
MPMonongahela Power Company, a West Virginia electric utility operating subsidiary of AE
NGC FirstEnergy Nuclear Generation Corp., owns nuclear generating facilities
OE Ohio Edison Company, an Ohio electric utility operating subsidiary
Ohio Companies CEI, OE and TE
PATHPotomac-Appalachian Transmission Highline LLC, a joint venture between Allegheny and a subsidiary of American Electric Power Company, Inc.
PATH-VAPATH Allegheny Virginia Transmission Corporation
PEThe Potomac Edison Company, a Maryland electric operating subsidiary of AE
Penelec Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
Penn Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
Pennsylvania Companies Met-Ed, Penelec, Penn and PennWP
PNBV PNBV Capital Trust, a special purpose entity created by OE in 1996
Shippingport Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
Signal Peak A joint venture between FirstEnergy Ventures Corp.FEV and WMB Loan Ventures LLC, that owns mining operations near Roundup, Montana
TE The Toledo Edison Company, an Ohio electric utility operating subsidiary
TrAILTrans-Allegheny Interstate Line Company
Utilities OE, 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:
   
ALJ Administrative Law Judge
AOCL Accumulated Other Comprehensive Loss
AEPAmerican Electric Power
AQC Air Quality Control
ARO Asset Retirement Obligation
BGS Basic Generation Service
CAA Clean Air Act
CAIR Clean Air Interstate Rule
CAMR Clean Air Mercury Rule
CATR Clean Air Transport Rule
CBP Competitive Bid Process
CDWRCalifornia Department of Water Resources
CO2
 Carbon Dioxide
CTC Competitive Transition Charge

iii

GLOSSARY OF TERMS, Cont’d.
DCPDDeferred Compensation Plan for Outside Directors
DOE United States Department of Energy
DOJ United States Department of Justice
DPA Department of the Public Advocate, Division of Rate Counsel (New Jersey)
DSPDefault Service Plan
EDCPExecutive Deferred Compensation Plan
EE&C Energy Efficiency and Conservation
EISEnergy Insurance Services, Inc.
EMP Energy Master Plan
ENECExpanded Net Energy Cost
EPA United States Environmental Protection Agency

iii

GLOSSARY OF TERMS, Cont’d.
ESOP Employee Stock Ownership Plan
ESP Electric Security Plan
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
FMB First Mortgage Bond
FPA Federal Power Act
FRR Fixed Resource Requirement
FTRsFinancial Transmission Rights
GAAP Generally Accepted Accounting Principles in the United States
RGGIRegional Greenhouse Gas Initiative
GHG Greenhouse Gases
IRS Internal Revenue Service
JOA Joint Operating Agreement
kV Kilovolt
KWH Kilowatt-hours
LED Light-Emitting Diode
LOC Letter of Credit
LTIPLong-Term Incentive Plan
MACT Maximum Achievable Control Technology
MDPSC Maryland Public Service Commission
MEIUG Met-Ed Industrial usersUsers Group
MISO Midwest Independent Transmission System Operator, Inc.
Moody’s Moody’s Investors Service, Inc.
MRO Market Rate Offer
MSHAMine Safety and Health Administration
MTEP MISO Regional Transmission Expansion Plan
MW Megawatts
MWH Megawatt-hours
NAAQS National Ambient Air Quality Standards
NDTNuclear Decommissioning Trusts
NERC North American Electric Reliability Corporation
NJBPU New Jersey Board of Public Utilities
NNSR Non-Attainment New Source Review
NOAC Northwest Ohio Aggregation Coalition
NOPEC Northeast Ohio Public Energy Council
NOV Notice of Violation
NOX
 Nitrogen Oxide
NRC Nuclear Regulatory Commission
NSR New Source Review
NUG Non-Utility Generation
NUGC Non-Utility Generation Charge
NYSEG New York State Electric and Gas
OCC Ohio Consumers’ Counsel
OCI Other Comprehensive Income
OPEB Other Post-Employment Benefits
OVEC Ohio Valley Electric Corporation
PADEPPennsylvania Department of Environmental Protection
PCRB Pollution Control Revenue Bond
PICA Pennsylvania Intergovernmental Cooperation Authority
PJM PJM Interconnection L. L. C.
POLR Provider of Last Resort; an electric utility’s obligation to provide generation service to customers whoseWhose alternative supplier fails to deliver service
PPUC Pennsylvania Public Utility Commission

iv

GLOSSARY OF TERMS, Cont’d.
PSCWV Public Service Commission of West Virginia
PSA Power Supply Agreement
PSD Prevention of Significant Deterioration
PUCO Public Utilities Commission of Ohio
PURPAPublic Utility Regulatory Policies Act of 1978
RECs Renewable Energy Credits
RFP Request for Proposal
RGGIRegional Greenhouse Gas Initiative
RTEP Regional Transmission Expansion Plan
RTC Regulatory Transition Charge
RTO Regional Transmission Organization
S&P Standard & Poor’s Ratings Service
SB221 Amended Substitute Senate Bill 221
SBC Societal Benefits Charge

iv

GLOSSARY OF TERMS, Cont’d.
SEC U.S. Securities and Exchange Commission
SIP State Implementation Plan(s) Under the Clean Air Act
SMIPSmart Meter Implementation Plan
SNCR Selective Non-Catalytic Reduction
SO2
 Sulfur Dioxide
SOSStandard Offer Service
TBC Transition Bond Charge
TDSTotal Dissolved Solid
TMDLTotal Maximum Daily Load
TMI-2 Three Mile Island Unit 2
TSC Transmission Service Charge
VIE Variable Interest Entity
VSCC Virginia State Corporation Commission
WVDEPWest Virginia Department of Environmental Protection
WVPSCPublic Service Commission of West Virginia

 

v

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
                 
 Three Months Nine Months  Three Months Ended 
 Ended September 30 Ended September 30  March 31 
 2010 2009 2010 2009 
In millions, except per share amounts 2011 2010 
 (In millions, except per share amounts)  
REVENUES:
  
Electric utilities $2,757 $2,940 $7,673 $8,751  $2,332 $2,543 
Unregulated businesses 936 468 2,449 1,262  1,244 756 
              
Total revenues* 3,693 3,408 10,122 10,013  3,576 3,299 
              
  
EXPENSES:
  
Fuel 400 302 1,084 890  453 334 
Purchased power 1,284 1,313 3,574 3,480  1,186 1,238 
Other operating expenses 738 665 2,112 2,103  1,033 701 
Provision for depreciation 182 188 565 550  220 193 
Amortization of regulatory assets 176 261 549 903  132 212 
Deferral of new regulatory assets — — —  (136)
General taxes 206 192 587 587  237 205 
Impairment of long-lived assets 292 — 294 — 
              
Total expenses 3,278 2,921 8,765 8,377  3,261 2,883 
              
  
OPERATING INCOME
 415 487 1,357 1,636  315 416 
              
  
OTHER INCOME (EXPENSE):
  
Investment income 46 191 93 207  21 16 
Interest expense  (208)  (355)  (628)  (755)  (231)  (213)
Capitalized interest 41 35 122 96  18 41 
              
Total other expense  (121)  (129)  (413)  (452)  (192)  (156)
              
  
INCOME BEFORE INCOME TAXES
 294 358 944 1,184  123 260 
  
INCOME TAXES
 119 128 364 430  78 111 
              
  
NET INCOME
 175 230 580 754  45 149 
  
Loss attributable to noncontrolling interest  (4)  (4)  (19)  (14)  (5)  (6)
              
  
EARNINGS AVAILABLE TO FIRSTENERGY CORP.
 $179 $234 $599 $768  $50 $155 
              
  
BASIC EARNINGS PER SHARE OF COMMON STOCK
 $0.59 $0.77 $1.97 $2.52  $0.15 $0.51 
              
  
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING
 304 304 304 304  342 304 
              
  
DILUTED EARNINGS PER SHARE OF COMMON STOCK
 $0.59 $0.77 $1.96 $2.51  $0.15 $0.51 
              
  
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING
 305 306 305 306  343 306 
              
  
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK
 $1.10 $1.10 $1.65 $1.65  $0.55 $0.55 
              
   
* Includes $119 and $109 million of excise tax collections of $120 million and $106 million in the three months ended September 30,March 31, 2011 and 2010, and 2009, respectively, and $328 million and $310 million in the nine months ended September 30, 2010 and 2009, respectively.
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

1

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
                 
  Three Months  Nine Months 
  Ended September 30  Ended September 30 
  2010  2009  2010  2009 
  (In millions) 
                 
NET INCOME
 $175  $230  $580  $754 
             
                 
OTHER COMPREHENSIVE INCOME (LOSS):
                
Pension and other postretirement benefits  17   (480)  47   24 
Unrealized gain on derivative hedges  6   19   16   57 
Change in unrealized gain on available-for-sale securities  20   (108)  32   (76)
             
Other comprehensive income (loss)  43   (569)  95   5 
Income tax expense (benefit) related to other comprehensive income  14   (216)  30   26 
             
Other comprehensive income (loss), net of tax  29   (353)  65   (21)
             
                 
COMPREHENSIVE INCOME (LOSS)
  204   (123)  645   733 
                 
COMPREHENSIVE LOSS ATTRIBUTABLE TO NONCONTROLLING INTEREST
  (4)  (4)  (19)  (14)
             
                 
COMPREHENSIVE INCOME (LOSS) AVAILABLE TO FIRSTENERGY CORP.
 $208  $(119) $664  $747 
             
         
  Three Months Ended 
  March 31 
(In millions) 2011  2010 
         
NET INCOME
 $45  $149 
       
         
OTHER COMPREHENSIVE INCOME:
        
Pension and other postretirement benefits  19   13 
Unrealized gain (loss) on derivative hedges  (6)  4 
Change in unrealized gain on available-for-sale securities  9   6 
       
Other comprehensive income  22   23 
Income tax expense related to other comprehensive income  1   7 
       
Other comprehensive income, net of tax  21   16 
       
         
COMPREHENSIVE INCOME
  66   165 
         
COMPREHENSIVE LOSS ATTRIBUTABLE TO NONCONTROLLING INTEREST
  (5)  (6)
       
         
COMPREHENSIVE INCOME AVAILABLE TO FIRSTENERGY CORP.
 $71  $171 
       
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

2

FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                
 September 30, December 31,  March 31, December 31, 
 2010 2009 
 (In millions) 
(In millions) 2011 2010 
ASSETS
  
  
CURRENT ASSETS:
  
Cash and cash equivalents $632 $874  $1,101 $1,019 
Receivables-  
Customers (less allowances of $39 million in 2010 and $33 million in 2009) 1,414 1,244 
Other (less allowances of $7 million in 2010 and 2009) 150 153 
Materials and supplies, at average cost 652 647 
Customers, net of allowance for uncollectible accounts of $38 in 2011 and $36 in 2010 1,636 1,392 
Other, net of allowance for uncollectible accounts of $10 in 2011 and $8 in 2010 229 176 
Materials and supplies 852 638 
Prepaid taxes 291 248  241 199 
Derivatives 377 182 
Other 252 154  210 92 
          
 3,391 3,320  4,646 3,698 
          
PROPERTY, PLANT AND EQUIPMENT:
  
In service 27,590 27,826  38,168 29,451 
Less — Accumulated provision for depreciation 11,206 11,397  11,345 11,180 
          
 16,384 16,429  26,823 18,271 
Construction work in progress 3,154 2,735  2,322 1,517 
Property, plant and equipment held for sale, net 490 — 
          
 19,538 19,164  29,635 19,788 
          
INVESTMENTS:
  
Nuclear plant decommissioning trusts 1,965 1,859  2,018 1,973 
Investments in lease obligation bonds 486 543  422 476 
Nuclear fuel disposal trust 207 208 
Other 564 621  434 345 
          
 3,015 3,023  3,081 3,002 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Goodwill 5,575 5,575  6,527 5,575 
Regulatory assets 2,246 2,356  2,084 1,826 
Power purchase contract asset 116 200 
Intangible assets 1,075 256 
Other 826 666  818 660 
          
 8,763 8,797  10,504 8,317 
          
 $34,707 $34,304  $47,866 $34,805 
          
LIABILITIES AND CAPITALIZATION
  
  
CURRENT LIABILITIES:
  
Currently payable long-term debt $1,590 $1,834  $1,385 $1,486 
Short-term borrowings 1,000 1,181  486 700 
Accounts payable 813 829  1,080 872 
Accrued taxes 230 314  412 326 
Accrued compensation and benefits 312 315 
Derivatives 425 266 
Other 1,339 1,130  1,062 733 
          
 4,972 5,288  5,162 4,698 
          
CAPITALIZATION:
  
Common stockholders’ equity-  
Common stock, $0.10 par value, authorized 375,000,000 shares- 304,835,407 shares outstanding 31 31 
Common stock, $0.10 par value, authorized 490,000,000 shares- 418,216,437 shares outstanding 42 31 
Other paid-in capital 5,445 5,448  9,779 5,444 
Accumulated other comprehensive loss  (1,350)  (1,415)  (1,518)  (1,539)
Retained earnings 4,591 4,495  4,426 4,609 
          
Total common stockholders’ equity 8,717 8,559  12,729 8,545 
Noncontrolling interest  (26)  (2)  (40)  (32)
          
Total equity 8,691 8,557  12,689 8,513 
Long-term debt and other long-term obligations 12,104 11,908  17,535 12,579 
          
 20,795 20,465  30,224 21,092 
          
 
NONCURRENT LIABILITIES:
  
Accumulated deferred income taxes 2,824 2,468  4,832 2,879 
Retirement benefits 1,541 1,534  2,313 1,868 
Asset retirement obligations 1,394 1,425  1,443 1,407 
Deferred gain on sale and leaseback transaction 968 993  951 959 
Power purchase contract liability 756 643  606 466 
Lease market valuation liability 228 262 
Other 1,229 1,226  2,335 1,436 
          
 8,940 8,551  12,480 9,015 
          
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
  
 $34,707 $34,304  $47,866 $34,805 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

3

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
                
 Nine Months Ended  Three Months Ended 
 September 30  March 31 
 2010 2009 
 (In millions) 
(In millions) 2011 2010 
  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income $580 $754  $45 $149 
Adjustments to reconcile net income to net cash from operating activities-  
Provision for depreciation 565 550  220 193 
Amortization of regulatory assets 549 903  132 212 
Deferral of new regulatory assets —  (136)
Nuclear fuel and lease amortization 123 92  47 41 
Deferred purchased power and other costs  (192)  (235)  (58)  (77)
Deferred income taxes and investment tax credits, net 259 421  171 59 
Impairment of long-lived assets 294 — 
Investment impairment 21 39 
Gain on investment securities held in trusts  (39)  (172)
Loss on debt redemption — 142 
Deferred rents and lease market valuation liability  (21)  (20)  (15)  (17)
Accrued compensation and retirement benefits 48 20   (13)  (81)
Interest rate swap transactions 129 — 
Commodity derivative transactions, net  (40) 26   (25) 33 
Cash collateral paid, net  (54)  (85)
Pension trust contribution —  (500)  (157) — 
Asset impairments 31 12 
Cash collateral paid  (28)  (46)
Decrease (increase) in operating assets-  
Receivables  (172) 78  164 2 
Materials and supplies  (6) 30  40  (42)
Prepayments and other current assets  (4)  (349) 118 33 
Increase (decrease) in operating liabilities-  
Accounts payable  (16)  (103)  (90)  (57)
Accrued taxes  (18)  (97)  (182) 7 
Accrued interest 63 121  76 66 
Other 4  (15) 15 19 
          
Net cash provided from operating activities 2,073 1,464  491 506 
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New Financing- 
New financing- 
Long-term debt 251 4,151  217 — 
Redemptions and Repayments- 
Redemptions and repayments- 
Long-term debt  (422)  (2,213)  (359)  (109)
Short-term borrowings, net  (171)  (764)  (214)  (295)
Common stock dividend payments  (503)  (503)  (190)  (168)
Other  (25)  (54)  (4)  (22)
          
Net cash provided from (used for) financing activities  (870) 617 
Net cash used for financing activities  (550)  (594)
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (1,467)  (1,575)  (449)  (508)
Proceeds from asset sales 117 19  — 114 
Sales of investment securities held in trusts 2,577 3,039  969 733 
Purchases of investment securities held in trusts  (2,610)  (3,101)  (993)  (755)
Customer acquisition costs  (110) —   (1)  (101)
Cash investments 56  (4) 47 49 
Restricted funds for debt redemption —  (150)
Cash received in Allegheny merger 590 — 
Other  (8)  (16)  (22)  (8)
          
Net cash used for investing activities  (1,445)  (1,788)
Net cash provided from (used for) investing activities 141  (476)
          
  
Net change in cash and cash equivalents  (242) 293  82  (564)
Cash and cash equivalents at beginning of period 874 545  1,019 874 
          
Cash and cash equivalents at end of period $632 $838  $1,101 $310 
          
 
SUPPLEMENTAL CASH FLOW INFORMATION:
 
Non-cash transaction: merger with Allegheny, common stock issued $4,354 $— 
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

4

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                 
 Three Months Ended Nine Months Ended  Three Months Ended 
 September 30 September 30  March 31 
(In thousands) 2011 2010 
 2010 2009 2010 2009  
 (In thousands) 
STATEMENTS OF INCOME
 
REVENUES:
  
Electric sales to non-affiliates $1,044,490 $668,685 
Electric sales to affiliates $599,695 $616,300 $1,745,542 $2,348,741  260,874 607,302 
Electric sales to non-affiliates 904,752 443,819 2,302,240 928,944 
Other 49,230 44,453 208,662 394,145  85,724 112,106 
              
Total revenues 1,553,677 1,104,572 4,256,444 3,671,830  1,391,088 1,388,093 
              
  
EXPENSES:
  
Fuel 391,087 294,693 1,061,719 871,160  343,109 328,221 
Purchased power from affiliates 116,381 35,290 246,232 149,746  68,743 60,953 
Purchased power from non-affiliates 411,084 205,200 1,160,119 551,155  296,938 450,216 
Other operating expenses 309,793 305,935 916,366 891,555  495,935 304,510 
Provision for depreciation 59,298 66,041 185,535 192,962  68,452 62,918 
General taxes 21,804 21,700 70,822 66,361  29,105 26,746 
Impairment of long-lived assets 291,934 — 293,767 —  13,800 1,833 
              
Total expenses 1,601,381 928,859 3,934,560 2,722,939  1,316,082 1,235,397 
              
  
OPERATING INCOME (LOSS)
  (47,704) 175,713 321,884 948,891 
OPERATING INCOME
 75,006 152,696 
              
  
OTHER INCOME (EXPENSE):
  
Investment income 29,895 158,857 43,978 135,723  5,861 717 
Miscellaneous income 4,765 2,804 10,468 12,840  19,241 3,143 
Interest expense — affiliates  (2,497)  (2,209)  (7,362)  (8,503)  (1,017)  (2,305)
Interest expense — other  (49,544)  (42,187)  (150,560)  (90,985)  (52,960)  (49,644)
Capitalized interest 22,955 17,869 66,550 41,975  9,919 19,690 
              
Total other income (expense) 5,574 135,134  (36,926) 91,050 
Total other expense  (18,956)  (28,399)
              
  
INCOME (LOSS) BEFORE INCOME TAXES
  (42,130) 310,847 284,958 1,039,941 
INCOME BEFORE INCOME TAXES
 56,050 124,297 
  
INCOME TAXES
  (5,404) 111,164 107,833 372,175  20,116 44,371 
              
  
NET INCOME (LOSS)
  (36,726) 199,683 177,125 667,766 
NET INCOME
 35,934 79,926 
     
 
Loss attributable to noncontrolling interest  (76) — 
     
 
EARNINGS AVAILABLE TO PARENT
 $36,010 $79,926 
     
 
STATEMENTS OF COMPREHENSIVE INCOME
 
 
NET INCOME
 $35,934 $79,926 
              
  
OTHER COMPREHENSIVE INCOME (LOSS):
  
Pension and other postretirement benefits 886  (61,085)  (8,063) 13,604  1,512  (9,834)
Unrealized gain on derivative hedges 2,818 790 7,109 26,847 
Unrealized gain (loss) on derivative hedges  (8,879) 1,274 
Change in unrealized gain on available-for-sale securities 17,445  (89,401) 28,533  (51,374) 7,807 5,028 
              
Other comprehensive income (loss) 21,149  (149,696) 27,579  (10,923) 440  (3,532)
Income taxes related to other comprehensive income (loss) 7,694  (58,883) 9,898  (3,549)
Income tax benefit related to other comprehensive income  (2,362)  (1,340)
              
Other comprehensive income (loss), net of tax 13,455  (90,813) 17,681  (7,374) 2,802  (2,192)
              
  
TOTAL COMPREHENSIVE INCOME (LOSS)
 $(23,271) $108,870 $194,806 $660,392 
COMPREHENSIVE INCOME
 38,736 77,734 
          
COMPREHENSIVE LOSS ATTRIBUTABLE TO NONCONTROLLING INTEREST
  (76) — 
     
 
COMPREHENSIVE INCOME ATTRIBUTABLE TO PARENT
 $38,812 $77,734 
     
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

5

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                
 September 30, December 31,  March 31, December 31, 
 2010 2009 
 (In thousands) 
(In thousands) 2011 2010 
ASSETS
  
 
CURRENT ASSETS:
  
Cash and cash equivalents $10 $12  $6,839 $9,281 
Receivables-  
Customers (less accumulated provisions of $16,277,000 and $12,041,000, respectively, for uncollectible accounts) 325,265 195,107 
Customers, net of allowance for uncollectible accounts of $18,636 in 2011 and $16,591 in 2010 388,951 365,758 
Associated companies 269,986 318,561  533,280 477,565 
Other (less accumulated provisions of $6,702,000 for uncollectible accounts) 57,407 51,872 
Other, net of allowances for uncollectible accounts of $6,702 in 2011 and $6,765 in 2010 86,711 89,550 
Notes receivable from associated companies 501,648 805,103  478,418 396,770 
Materials and supplies, at average cost 554,043 539,541  488,997 545,342 
Derivatives 328,156 181,660 
Prepayments and other 204,065 107,782  50,938 60,171 
          
 1,912,424 2,017,978  2,362,290 2,126,097 
          
PROPERTY, PLANT AND EQUIPMENT:
  
In service 9,663,264 10,357,632  11,239,565 11,321,318 
Less — Accumulated provision for depreciation 4,114,381 4,531,158  4,107,542 4,024,280 
          
 5,548,883 5,826,474  7,132,023 7,297,038 
Construction work in progress 2,736,635 2,423,446  756,305 1,062,744 
Property, plant and equipment held for sale, net 476,602 — 
          
 8,285,518 8,249,920  8,364,930 8,359,782 
          
INVESTMENTS:
  
Nuclear plant decommissioning trusts 1,158,376 1,088,641  1,159,903 1,145,846 
Other 7,400 22,466  9,744 11,704 
          
 1,165,776 1,111,107  1,169,647 1,157,550 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Accumulated deferred income tax benefits 3,357 86,626 
Customer intangibles 127,420 16,566  131,870 133,968 
Goodwill 24,248 24,248  24,248 24,248 
Property taxes 50,125 50,125  41,112 41,112 
Unamortized sale and leaseback costs 61,934 72,553  90,803 73,386 
Derivatives 211,223 97,603 
Other 164,332 121,665  53,057 48,689 
          
 431,416 371,783  552,313 419,006 
          
 $11,795,134 $11,750,788  $12,449,180 $12,062,435 
          
LIABILITIES AND CAPITALIZATION
  
 
CURRENT LIABILITIES:
  
Currently payable long-term debt $1,396,792 $1,550,927  $986,863 $1,132,135 
Short-term borrowings-  
Associated companies 9,642 9,237  360,543 11,561 
Other 100,000 100,000  661 — 
Accounts payable-  
Associated companies 472,018 466,078  499,936 466,623 
Other 204,928 245,363  189,144 241,191 
Accrued taxes 59,422 83,158  66,493 70,129 
Derivatives 380,744 266,411 
Other 430,824 359,057  224,525 251,671 
          
 2,673,626 2,813,820  2,708,909 2,439,721 
          
CAPITALIZATION:
  
Common stockholders’ equity-  
Common stock, without par value, authorized 750 shares, 7 shares outstanding 1,490,010 1,468,423 
Common stock, without par value, authorized 750 shares- 7 shares outstanding 1,487,565 1,490,082 
Accumulated other comprehensive loss  (85,320)  (103,001)  (117,612)  (120,414)
Retained earnings 2,326,274 2,149,149  2,454,587 2,418,577 
          
Total common stockholders’ equity 3,730,964 3,514,571  3,824,540 3,788,245 
Noncontrolling interest 16  (504)
     
Total equity 3,824,556 3,787,741 
Long-term debt and other long-term obligations 2,819,150 2,711,652  3,144,997 3,180,875 
          
 6,550,114 6,226,223  6,969,553 6,968,616 
          
NONCURRENT LIABILITIES:
  
Deferred gain on sale and leaseback transaction 967,583 992,869  950,726 959,154 
Accumulated deferred income taxes 117,503 57,595 
Accumulated deferred investment tax credits 55,267 58,396  53,181 54,224 
Asset retirement obligations 877,522 921,448  866,643 892,051 
Retirement benefits 228,779 204,035  289,285 285,160 
Property taxes 50,125 50,125  41,112 41,112 
Lease market valuation liability 228,119 262,200  205,366 216,695 
Derivatives 168,409 81,393 
Other 163,999 221,672  78,493 66,714 
          
 2,571,394 2,710,745  2,770,718 2,654,098 
          
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
  
 $11,795,134 $11,750,788  $12,449,180 $12,062,435 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

6

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
                
 Nine Months Ended  Three Months Ended 
 September 30  March 31 
 2010 2009 
 (In thousands) 
(In thousands) 2011 2010 
  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income $177,125 $667,766  $35,934 $79,926 
Adjustments to reconcile net income to net cash from operating activities-  
Provision for depreciation 185,535 192,962  68,452 62,918 
Nuclear fuel and lease amortization 126,071 94,244  46,653 42,118 
Deferred rents and lease market valuation liability  (41,493)  (40,143)  (38,759)  (40,869)
Deferred income taxes and investment tax credits, net 96,152 268,812  61,268 37,773 
Impairment of long-lived assets 293,767 — 
Investment impairment 21,089 36,169 
Accrued compensation and retirement benefits 15,887 5,860 
Asset impairments 18,791 11,439 
Commodity derivative transactions, net  (40,048) 25,794   (35,293) 32,900 
Gain on asset sales  (2,213)  (9,832)
Gain on investment securities held in trusts  (34,292)  (154,723)
Cash collateral, net  (53,900)  (92,618)
Cash collateral paid  (27,063)  (21,411)
Decrease (increase) in operating assets-  
Receivables  (91,134)  (55,774)  (76,069)  (158,288)
Materials and supplies  (15,324) 38,543  60,633  (8,700)
Prepayments and other current assets 36,004  (35,315) 8,728 13,516 
Increase (decrease) in operating liabilities-  
Accounts payable  (50,114)  (72,181)  (18,734)  (41,057)
Accrued taxes  (8,404) 23,846   (3,164)  (16,300)
Accrued interest  (14,130) 31,770   (11,845)  (14,930)
Other 23,349  (43,369) 4,093 12,069 
          
Net cash provided from operating activities 623,927 881,811 
Net cash provided from (used for) operating activities 93,625  (8,896)
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New Financing- 
New financing- 
Long-term debt 249,520 2,356,762  150,190 — 
Short-term borrowings, net 405 —  349,643 — 
Redemptions and Repayments- 
Redemptions and repayments- 
Long-term debt  (296,339)  (618,213)  (331,428)  (1,278)
Short-term borrowings, net —  (1,164,823) —  (9,237)
Other  (798)  (20,006)  (1,017)  (731)
          
Net cash provided from (used for) financing activities  (47,212) 553,720  167,388  (11,246)
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (801,238)  (842,600)  (159,006)  (301,603)
Proceeds from asset sales 117,213 16,129  — 114,272 
Sales of investment securities held in trusts 1,478,086 2,152,717  215,620 272,094 
Purchases of investment securities held in trusts  (1,511,273)  (2,175,135)  (230,912)  (284,888)
Loans from (to) associated companies, net 303,455  (298,841)  (81,647) 321,680 
Customer acquisition costs  (110,073) —   (1,103)  (100,615)
Leasehold improvement payments to associated companies  (51,204) — 
Other  (1,683)  (20,882)  (6,407)  (799)
          
Net cash used for investing activities  (576,717)  (1,168,612)
Net cash provided from (used for) investing activities  (263,455) 20,141 
          
  
Net change in cash and cash equivalents  (2) 266,919   (2,442)  (1)
Cash and cash equivalents at beginning of period 12 39  9,281 12 
          
Cash and cash equivalents at end of period $10 $266,958  $6,839 $11 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

7

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                 
 Three Months Ended Nine Months Ended  Three Months Ended 
 September 30 September 30  March 31 
 2010 2009 2010 2009 
(In thousands) 2011 2010 
 (In thousands)  
STATEMENTS OF INCOME
  
  
REVENUES:
  
Electric sales $456,531 $575,377 $1,351,893 $1,942,612  $363,831 $479,925 
Excise and gross receipts tax collections 30,058 27,127 82,482 81,055  28,195 28,475 
              
Total revenues 486,589 602,504 1,434,375 2,023,667  392,026 508,400 
              
  
EXPENSES:
  
Purchased power from affiliates 136,804 200,506 424,530 847,712  93,262 153,677 
Purchased power from non-affiliates 84,264 161,732 257,322 397,875  60,379 94,231 
Other operating expenses 94,804 102,463 271,934 372,231 
Other operating costs 101,462 88,855 
Provision for depreciation 21,990 22,407 65,884 65,916  21,876 21,880 
Amortization of regulatory assets, net 9,704 17,404 48,473 59,910  774 29,345 
General taxes 48,909 45,164 139,763 138,187  49,426 47,492 
              
Total expenses 396,475 549,676 1,207,906 1,881,831  327,179 435,480 
              
  
OPERATING INCOME
 90,114 52,828 226,469 141,836  64,847 72,920 
              
  
OTHER INCOME (EXPENSE):
  
Investment income 5,438 20,285 16,991 39,796  4,308 5,244 
Miscellaneous income 1,673 237 2,676 2,108 
Miscellaneous income (expense) 290  (292)
Interest expense  (21,975)  (22,961)  (66,440)  (67,717)  (22,145)  (22,310)
Capitalized interest 335 231 838 730  331 208 
              
Total other expense  (14,529)  (2,208)  (45,935)  (25,083)  (17,216)  (17,150)
              
  
INCOME BEFORE INCOME TAXES
 75,585 50,620 180,534 116,753  47,631 55,770 
  
INCOME TAXES
 29,332 15,885 60,797 36,742  17,491 19,609 
              
  
NET INCOME
 46,253 34,735 119,737 80,011  30,140 36,161 
              
  
Income from noncontrolling interest 124 140 386 429 
Income attributable to noncontrolling interest 116 132 
              
  
EARNINGS AVAILABLE TO PARENT
 $46,129 $34,595 $119,351 $79,582  $30,024 $36,029 
              
  
STATEMENTS OF COMPREHENSIVE INCOME
  
  
NET INCOME
 $46,253 $34,735 $119,737 $80,011  $30,140 $36,161 
              
  
OTHER COMPREHENSIVE INCOME LOSS:
 
OTHER COMPREHENSIVE INCOME (LOSS):
 
Pension and other postretirement benefits 321  (49,043) 4,658 46,559  339 4,015 
Change in unrealized gain on available-for-sale securities 2,178  (7,695) 2,989  (9,676)  (22) 291 
              
Other comprehensive income (loss) 2,499  (56,738) 7,647 36,883 
Other comprehensive income 317 4,306 
Income tax expense (benefit) related to other comprehensive income 562  (21,924) 1,229 15,915   (1,496) 693 
              
Other comprehensive income (loss), net of tax 1,937  (34,814) 6,418 20,968 
Other comprehensive income, net of tax 1,813 3,613 
              
  
COMPREHENSIVE INCOME (LOSS)
 48,190  (79) 126,155 100,979 
COMPREHENSIVE INCOME
 31,953 39,774 
  
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST
 124 140 386 429  116 132 
              
  
COMPREHENSIVE INCOME (LOSS) AVAILABLE TO PARENT
 $48,066 $(219) $125,769 $100,550 
COMPREHENSIVE INCOME AVAILABLE TO PARENT
 $31,837 $39,642 
              
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

8

OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                
 September 30, December 31,  March 31, December 31, 
 2010 2009 
(In thousands) 2011 2010 
 (In thousands)  
ASSETS
  
CURRENT ASSETS:
  
Cash and cash equivalents $288,092 $324,175  $345,030 $420,489 
Receivables-  
Customers (less accumulated provisions of $4,951,000 and $5,119,000, respectively, for uncollectible accounts) 182,894 209,384 
Customers (net of allowance for uncollectible accounts of $3,774 in 2011 and $4,086 in 2010) 158,146 176,591 
Associated companies 38,499 98,874  74,125 118,135 
Other 20,777 14,155  17,290 12,232 
Notes receivable from associated companies 16,234 118,651  16,762 16,957 
Prepayments and other 9,490 15,964  29,366 6,393 
          
 555,986 781,203  640,719 750,797 
          
UTILITY PLANT:
  
In service 3,118,239 3,036,467  3,156,648 3,136,623 
Less — Accumulated provision for depreciation 1,199,401 1,165,394  1,217,827 1,207,745 
          
 1,918,838 1,871,073  1,938,821 1,928,878 
Construction work in progress 38,915 31,171  48,302 45,103 
          
 1,957,753 1,902,244  1,987,123 1,973,981 
          
OTHER PROPERTY AND INVESTMENTS:
  
Investment in lease obligation bonds 204,707 216,600  190,340 190,420 
Nuclear plant decommissioning trusts 129,685 120,812  126,826 127,017 
Other 96,897 96,861  94,604 95,563 
          
 431,289 434,273  411,770 413,000 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Regulatory assets 413,596 465,331  385,005 400,322 
Pension assets 39,271 19,881  59,104 28,596 
Property taxes 67,037 67,037  71,331 71,331 
Unamortized sale and leaseback costs 31,376 35,127  28,877 30,126 
Other 17,540 39,881  16,007 17,634 
          
 568,820 627,257  560,324 548,009 
          
 $3,513,848 $3,744,977  $3,599,936 $3,685,787 
          
LIABILITIES AND CAPITALIZATION
  
CURRENT LIABILITIES:
  
Currently payable long-term debt $1,479 $2,723  $1,424 $1,419 
Short-term borrowings-  
Associated companies 47,648 92,863  103,071 142,116 
Other 320 807  320 320 
Accounts payable-  
Associated companies 32,084 102,763  96,003 99,421 
Other 23,994 40,423  25,515 29,639 
Accrued taxes 55,236 81,868  68,415 78,707 
Accrued interest 25,354 25,749  25,334 25,382 
Other 133,060 81,424  105,315 74,947 
          
 319,175 428,620  425,397 451,951 
          
CAPITALIZATION:
  
Common stockholder’s equity- 
Common stock, without par value, authorized 175,000,000 shares - 60 shares outstanding 951,839 1,154,797 
Common stockholders’ equity- 
Common stock, without par value, authorized 175,000,000 shares- 60 shares outstanding 951,802 951,866 
Accumulated other comprehensive loss  (157,159)  (163,577)  (177,263)  (179,076)
Retained earnings 104,241 29,890  71,645 141,621 
          
Total common stockholder’s equity 898,921 1,021,110 
Total common stockholders’ equity 846,184 914,411 
Noncontrolling interest 6,225 6,442  5,796 5,680 
          
Total equity 905,146 1,027,552  851,980 920,091 
Long-term debt and other long-term obligations 1,152,370 1,160,208  1,152,171 1,152,134 
     
      2,004,151 2,072,225 
 2,057,516 2,187,760      
      
NONCURRENT LIABILITIES:
  
Accumulated deferred income taxes 678,815 660,114  719,979 696,410 
Accumulated deferred investment tax credits 10,521 11,406  9,799 10,159 
Retirement benefits 169,070 174,925  182,461 183,712 
Asset retirement obligations 83,194 85,926  69,793 74,456 
Other 195,557 196,226  188,356 196,874 
          
 1,137,157 1,128,597  1,170,388 1,161,611 
          
COMMITMENTS AND CONTINGENCIES (Note 9)
  
 $3,513,848 $3,744,977  $3,599,936 $3,685,787 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

9

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
                
 Nine Months Ended  Three Months Ended 
 September 30  March 31 
 2010 2009 
 (In thousands) 
(In thousands) 2011 2010 
  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income $119,737 $80,011  $30,140 $36,161 
Adjustments to reconcile net income to net cash from operating activities-  
Provision for depreciation 65,884 65,916  21,876 21,880 
Amortization of regulatory assets, net 48,473 59,910  774 29,345 
Purchased power cost recovery reconciliation 3,906 15,372   (4,926)  (5,908)
Amortization of lease costs 28,314 28,394  32,933 32,934 
Deferred income taxes and investment tax credits, net 7,612 32,658  26,682  (2,489)
Accrued compensation and retirement benefits  (16,659)  (3,542)  (7,944)  (12,160)
Accrued regulatory obligations 1,301 19,172 
Electric service prepayment programs —  (4,634)
Cash collateral from suppliers 23,286 6,469 
Pension trust contributions —  (103,035)
Pension trust contribution  (27,000) — 
Decrease (increase) in operating assets-  
Receivables 91,971 128,688  82,291 65,141 
Prepayments and other current assets 10,331  (2,553)  (22,973)  (21,802)
Decrease in operating liabilities-  
Accounts payable  (87,108)  (60,125)  (19,625)  (35,461)
Accrued taxes  (26,425)  (17,196)  (10,305)  (15,849)
Accrued interest  (395)  (59)  (48)  (226)
Other  (9,695)  (8,596) 2,438 9,647 
          
Net cash provided from operating activities 260,533 236,850  104,313 101,213 
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New Financing- 
Long-term debt — 100,000 
Short-term borrowings, net — 74,514 
Redemptions and Repayments- 
Redemptions and repayments- 
Long-term debt  (9,628)  (101,088)  (110)  (1,363)
Short-term borrowings, net  (45,702) —   (39,045)  (92,863)
Common stock dividend payments  (250,000)  (150,000)  (100,000)  (250,000)
Other  (892)  (2,138) —  (113)
          
Net cash used for financing activities  (306,222)  (78,712)  (139,155)  (344,339)
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (110,645)  (108,253)  (37,651)  (35,680)
Leasehold improvement payments from associated companies 18,375 — 
Sales of investment securities held in trusts 78,599 207,280  7,972 2,424 
Purchases of investment securities held in trusts  (83,725)  (214,592)  (8,896)  (2,971)
Loan repayments from associated companies, net 102,417 134,975  195 14,469 
Cash investments 12,296 7,070   (136)  (384)
Other  (7,711)  (1,216)  (2,101) 1,773 
          
Net cash provided from investing activities 9,606 25,264 
Net cash used for investing activities  (40,617)  (20,369)
          
  
Net change in cash and cash equivalents  (36,083) 183,402   (75,459)  (263,495)
Cash and cash equivalents at beginning of period 324,175 146,343  420,489 324,175 
          
Cash and cash equivalents at end of period $288,092 $329,745  $345,030 $60,680 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

10

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                 
 Three Months Ended Nine Months Ended  Three Months Ended 
 September 30 September 30  March 31 
 2010 2009 2010 2009 
(In thousands) 2011 2010 
 (In thousands)  
STATEMENTS OF INCOME
  
 
REVENUES:
  
Electric sales $309,236 $417,900 $901,913 $1,307,592  $206,742 $312,497 
Excise tax collections 19,480 17,629 52,548 52,748  18,145 17,573 
              
Total revenues 328,716 435,529 954,461 1,360,340  224,887 330,070 
              
  
EXPENSES:
  
Purchased power from affiliates 89,389 153,556 298,204 635,927  46,168 109,393 
Purchased power from non-affiliates 35,151 87,689 105,200 208,849  18,220 37,398 
Other operating expenses 36,441 37,822 96,613 141,829  35,036 31,235 
Provision for depreciation 18,057 17,753 54,504 53,885  18,426 18,111 
Amortization of regulatory assets 45,136 39,313 121,082 325,630  23,370 45,139 
Deferral of new regulatory assets — — —  (134,587)
General taxes 39,878 37,752 107,207 112,749  40,212 38,489 
              
Total expenses 264,052 373,885 782,810 1,344,282  181,432 279,765 
              
  
OPERATING INCOME
 64,664 61,644 171,651 16,058  43,455 50,305 
              
  
OTHER INCOME (EXPENSE):
  
Investment income 6,604 7,565 20,756 23,599  6,597 7,547 
Miscellaneous income 533 645 1,790 3,437  636 581 
Interest expense  (33,384)  (34,740)  (100,267)  (100,819)  (33,078)  (33,621)
Capitalized interest 10 27 43 145  27 26 
              
Total other expense  (26,237)  (26,503)  (77,678)  (73,638)  (25,818)  (25,467)
              
  
INCOME (LOSS) BEFORE INCOME TAXES
 38,427 35,141 93,973  (57,580)
INCOME BEFORE INCOME TAXES
 17,637 24,838 
  
INCOME TAX EXPENSE (BENEFIT)
 13,479 9,755 33,107  (25,290)
INCOME TAXES
 4,436 10,843 
              
  
NET INCOME (LOSS)
 24,948 25,386 60,866  (32,290)
NET INCOME
 13,201 13,995 
              
  
Income from noncontrolling interest 366 418 1,151 1,295 
Income attributable to noncontrolling interest 366 419 
              
  
EARNINGS (LOSS) AVAILABLE TO PARENT
 $24,582 $24,968 $59,715 $(33,585)
EARNINGS AVAILABLE TO PARENT
 $12,835 $13,576 
              
  
STATEMENTS OF COMPREHENSIVE INCOME
  
  
NET INCOME (LOSS)
 $24,948 $25,386 $60,866 $(32,290)
NET INCOME
 $13,201 $13,995 
              
  
OTHER COMPREHENSIVE INCOME (LOSS):
  
Pension and other postretirement benefits 3,228  (48,024)  (16,129)  (154) 2,967  (22,585)
Unrealized loss on derivative hedges —  (1,451) —  (1,451)
         
Other comprehensive income (loss) 3,228  (49,475)  (16,129)  (1,605)
Income tax expense (benefit) related to other comprehensive income 976  (17,854)  (6,325) 1,452 
Income tax benefit related to other comprehensive income  (462)  (8,277)
              
Other comprehensive income (loss), net of tax 2,252  (31,621)  (9,804)  (3,057) 3,429  (14,308)
              
  
COMPREHENSIVE INCOME (LOSS)
 27,200  (6,235) 51,062  (35,347) 16,630  (313)
  
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST
 366 418 1,151 1,295  366 419 
              
  
COMPREHENSIVE INCOME (LOSS) AVAILABLE TO PARENT
 $26,834 $(6,653) $49,911 $(36,642)
TOTAL COMPREHENSIVE INCOME (LOSS) AVAILABLE TO PARENT
 $16,264 $(732)
              
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

11

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                
 September 30, December 31,  March 31, December 31, 
 2010 2009 
(In thousands) 2011 2010 
 (In thousands)  
ASSETS
  
  
CURRENT ASSETS:
  
Cash and cash equivalents $247 $86,230  $30,244 $238 
Receivables-  
Customers (less accumulated provisions of $5,271,000 and $5,239,000, respectively, for uncollectible accounts) 186,044 209,335 
Customers (less allowance for doubtful accounts of $3,018 in 2011 and $4,589 in 2010, respectively) 107,418 183,744 
Associated companies 59,339 98,954  34,819 77,047 
Other 4,910 11,661  4,848 11,544 
Notes receivable from associated companies 23,905 26,802  22,704 23,236 
Prepayments and other 4,362 9,973  13,894 3,656 
          
 278,807 442,955  213,927 299,465 
          
UTILITY PLANT:
  
In service 2,373,419 2,310,074  2,407,827 2,396,893 
Less — Accumulated provision for depreciation 921,040 888,169  937,105 932,246 
          
 1,452,379 1,421,905  1,470,722 1,464,647 
Construction work in progress 30,482 36,907  48,572 38,610 
          
 1,482,861 1,458,812  1,519,294 1,503,257 
          
OTHER PROPERTY AND INVESTMENTS:
  
Investment in lessor notes 340,031 388,641  286,747 340,029 
Other 10,084 10,220  10,035 10,074 
          
 350,115 398,861  296,782 350,103 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Goodwill 1,688,521 1,688,521  1,688,521 1,688,521 
Regulatory assets 420,144 545,505  337,189 370,403 
Pension assets (Note 6) — 13,380 
Property taxes 77,319 77,319  80,614 80,614 
Other 12,897 12,777  11,176 11,486 
          
 2,198,881 2,337,502  2,117,500 2,151,024 
          
 $4,310,664 $4,638,130  $4,147,503 $4,303,849 
          
LIABILITIES AND CAPITALIZATION
  
  
CURRENT LIABILITIES:
  
Currently payable long-term debt $148 $117  $174 $161 
Short-term borrowings-  
Associated companies 129,912 339,728  23,303 105,996 
Accounts payable-  
Associated companies 14,803 68,634  43,564 32,020 
Other 13,725 17,166  8,811 14,947 
Accrued taxes 64,492 90,511  75,771 84,668 
Accrued interest 39,261 18,466  39,256 18,555 
Other 63,732 45,440  40,862 44,569 
          
 326,073 580,062  231,741 300,916 
          
CAPITALIZATION:
  
Common stockholders’ equity- 
Common stock, without par value, authorized 105,000,000 shares, 67,930,743 shares outstanding 886,927 884,897 
Common stockholder’s equity- 
Common stock, without par value, authorized 105,000,000 shares- 67,930,743 shares outstanding 886,995 887,087 
Accumulated other comprehensive loss  (147,962)  (138,158)  (149,758)  (153,187)
Retained earnings 556,963 597,248  531,741 568,906 
          
Total common stockholders’ equity 1,295,928 1,343,987 
Total common stockholder’s equity 1,268,978 1,302,806 
Noncontrolling interest 17,651 20,592  14,886 18,017 
          
Total equity 1,313,579 1,364,579  1,283,864 1,320,823 
Long-term debt and other long-term obligations 1,852,511 1,872,750  1,831,011 1,852,530 
     
      3,114,875 3,173,353 
 3,166,090 3,237,329      
      
NONCURRENT LIABILITIES:
  
Accumulated deferred income taxes 628,244 644,745  631,507 622,771 
Accumulated deferred investment tax credits 11,205 11,836  10,784 10,994 
Retirement benefits 82,070 69,733  60,682 95,654 
Other 96,982 94,425  97,914 100,161 
          
 818,501 820,739  800,887 829,580 
          
COMMITMENTS AND CONTINGENCIES (Note 9)
 
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
 
 $4,310,664 $4,638,130  $4,147,503 $4,303,849 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

12

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)
                
 Nine Months Ended  Three Months Ended 
 September 30  March 31 
 2010 2009 
 (In thousands) 
(In thousands) 2011 2010 
  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income (Loss) $60,866 $(32,290)
Adjustments to reconcile net income (loss) to net cash from operating activities- 
Net Income $13,201 $13,995 
Adjustments to reconcile net income to net cash from operating activities- 
Provision for depreciation 54,504 53,885  18,426 18,111 
Amortization of regulatory assets, net 121,082 325,630  23,370 45,139 
Deferral of new regulatory assets —  (134,587)
Purchased power cost recovery reconciliation —  (3,478)
Deferred income taxes and investment tax credits, net  (24,283)  (41,939) 4,140  (13,627)
Accrued compensation and retirement benefits 10,467 10,311  2,158 2,282 
Accrued regulatory obligations  (863)  (26)
Pension trust contribution —  (89,789)  (35,000) — 
Electric service prepayment programs —  (3,510)
Cash collateral from suppliers, net 19,245 5,404 
Decrease (increase) in operating assets-  
Receivables 86,725 30,977  136,887 70,633 
Prepayments and other current assets 5,421  (633)  (10,236)  (9,133)
Increase (decrease) in operating liabilities-  
Accounts payable  (57,272)  (32,240) 5,408  (14,387)
Accrued taxes  (23,876)  (17,003)  (8,898)  (16,616)
Accrued interest 20,795 29,816  20,701 20,795 
Other 740 11,489   (3,870)  (2,636)
          
Net cash provided from operating activities 274,414 112,043  165,424 114,530 
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New Financing- 
Long-term debt — 298,398 
Redemptions and Repayments- 
Redemptions and repayments- 
Long-term debt  (84)  (558)  (36)  (26)
Short-term borrowings, net  (230,132)  (111,128)  (104,228)  (126,334)
Common stock dividend payments  (100,000)  (93,000)  (50,000)  (100,000)
Other  (4,100)  (6,161)  (3,497)  (3,365)
          
Net cash provided from (used for) financing activities  (334,316) 87,551 
Net cash used for financing activities  (157,761)  (229,725)
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (70,812)  (73,577)  (29,334)  (19,735)
Restricted cash —  (155,573)
Loan repayments from (to) associated companies, net 2,897  (4,638)
Loans to associated companies, net 532 1,426 
Redemptions of lessor notes 48,610 37,072  53,282 48,606 
Other  (6,776)  (2,871)  (2,137)  (1,085)
          
Net cash used for investing activities  (26,081)  (199,587)
Net cash provided from investing activities 22,343 29,212 
          
  
Net change in cash and cash equivalents  (85,983) 7  30,006  (85,983)
Cash and cash equivalents at beginning of period 86,230 226  238 86,230 
          
Cash and cash equivalents at end of period $247 $233  $30,244 $247 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

13

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                        
 Three Months Ended Nine Months Ended  Three Months Ended 
 September 30 September 30  March 31 
 2010 2009 2010 2009 
(In thousands) 2011 2010 
 (In thousands)  
STATEMENTS OF INCOME
  
  
REVENUES:
  
Electric sales $136,058 $206,086 $376,180 $663,082  $106,325 $125,431 
Excise tax collections 7,979 7,422 21,079 21,448  7,302 7,041 
              
Total revenues 144,037 213,508 397,259 684,530  113,627 132,472 
              
  
EXPENSES:
  
Purchased power from affiliates 42,338 86,278 144,062 342,166  35,517 54,618 
Purchased power from non-affiliates 16,663 56,494 50,377 115,275  13,988 18,491 
Other operating expenses 28,746 30,238 79,790 110,722  36,587 25,545 
Provision for depreciation 7,800 7,847 23,763 23,136  7,931 7,950 
Amortization (deferral) of regulatory assets, net 6,591 9,253  (3,708) 30,921 
Deferral of regulatory assets, net  (11,478)  (8,499)
General taxes 14,023 13,205 39,766 39,804  14,452 13,461 
              
Total expenses 116,161 203,315 334,050 662,024  96,997 111,566 
              
  
OPERATING INCOME
 27,876 10,193 63,209 22,506  16,630 20,906 
              
  
OTHER INCOME (EXPENSE):
  
Investment income 3,018 9,302 11,875 22,315  2,922 3,800 
Miscellaneous expense  (502)  (1,725)  (2,853)  (1,690)  (1,629)  (1,406)
Interest expense  (10,479)  (10,854)  (31,421)  (25,649)  (10,443)  (10,487)
Capitalized interest 94 46 252 138  102 78 
              
Total other expense  (7,869)  (3,231)  (22,147)  (4,886)  (9,048)  (8,015)
              
  
INCOME BEFORE INCOME TAXES
 20,007 6,962 41,062 17,620  7,582 12,891 
  
INCOME TAX EXPENSE (BENEFIT)
 6,911  (138) 13,241 3,123 
INCOME TAXES
 1,735 5,382 
              
  
NET INCOME
 13,096 7,100 27,821 14,497  5,847 7,509 
              
  
Income from noncontrolling interest  (4) 14 1 17 
Income attributable to noncontrolling interest 2 3 
              
  
EARNINGS AVAILABLE TO PARENT
 $13,100 $7,086 $27,820 $14,480  $5,845 $7,506 
              
  
STATEMENTS OF COMPREHENSIVE INCOME
  
  
NET INCOME
 $13,096 $7,100 $27,821 $14,497  $5,847 $7,509 
              
  
OTHER COMPREHENSIVE INCOME (LOSS):
 
OTHER COMPREHENSIVE INCOME:
 
Pension and other postretirement benefits 713  (24,201) 1,723  (5,052) 592 296 
Change in unrealized gain on available-for-sale securities 427  (11,633) 466  (15,181) 1,305 369 
              
Other comprehensive income (loss) 1,140  (35,834) 2,189  (20,233)
Income tax expense (benefit) related to other comprehensive income 330  (13,187) 565  (5,982)
Other comprehensive income 1,897 665 
Income tax expense related to other comprehensive income 334 170 
              
Other comprehensive income (loss), net of tax 810  (22,647) 1,624  (14,251)
Other comprehensive income, net of tax 1,563 495 
              
  
COMPREHENSIVE INCOME (LOSS)
 13,906  (15,547) 29,445 246 
COMPREHENSIVE INCOME
 7,410 8,004 
  
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTEREST
  (4) 14 1 17 
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST
 2 3 
              
  
COMPREHENSIVE INCOME (LOSS) AVAILABLE TO PARENT
 $13,910 $(15,561) $29,444 $229 
COMPREHENSIVE INCOME AVAILABLE TO PARENT
 $7,408 $8,001 
              
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

14

THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                
 September 30, December 31,  March 31, December 31, 
 2010 2009 
(In thousands) 2011 2010 
 (In thousands)  
ASSETS
  
  
CURRENT ASSETS:
  
Cash and cash equivalents $134,158 $436,712  $150,014 $149,262 
Receivables-  
Customers 30 75 
Customers (net of allowance for uncollectible accounts of $1,209 in 2011 and $1 in 2010) 45,749 29 
Associated companies 44,075 90,191  56,913 31,777 
Other (less accumulated provisions of $224,000 and $208,000, respectively, for uncollectible accounts) 19,146 20,180 
Other (net of allowance for uncollectible accounts of $343 in 2011 and $330 in 2010) 18,752 18,464 
Notes receivable from associated companies 81,254 85,101  35,489 96,765 
Prepayments and other 4,272 7,111  8,302 2,306 
          
 282,935 639,370  315,219 298,603 
          
UTILITY PLANT:
  
In service 938,532 912,930  952,874 947,203 
Less — Accumulated provision for depreciation 440,510 427,376  449,791 446,401 
          
 498,022 485,554  503,083 500,802 
Construction work in progress 9,946 9,069  12,647 12,604 
          
 507,968 494,623  515,730 513,406 
          
OTHER PROPERTY AND INVESTMENTS:
  
Investment in lessor notes 103,848 124,357  82,133 103,872 
Nuclear plant decommissioning trusts 76,051 73,935  77,141 75,558 
Other 1,514 1,580  1,469 1,492 
          
 181,413 199,872  160,743 180,922 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Goodwill 500,576 500,576  500,576 500,576 
Regulatory assets 74,297 69,557  83,544 72,059 
Pension assets 24,427 — 
Property taxes 23,658 23,658  24,990 24,990 
Other 27,215 55,622  36,167 23,750 
          
 625,746 649,413  669,704 621,375 
          
 $1,598,062 $1,983,278  $1,661,396 $1,614,306 
          
LIABILITIES AND CAPITALIZATION
  
  
CURRENT LIABILITIES:
  
Currently payable long-term debt $208 $222  $191 $199 
Accounts payable-  
Associated companies 8,644 78,341  36,055 17,168 
Other 6,212 8,312  5,238 7,351 
Notes payable to associated companies — 225,975 
Accrued taxes 17,904 25,734  23,043 24,401 
Accrued interest 15,983 5,931 
Lease market valuation liability 36,900 36,900  36,900 36,900 
Other 44,745 29,273  54,905 23,145 
          
 114,613 404,757  172,315 115,095 
          
CAPITALIZATION:
  
Common stockholders’ equity-  
Common stock, $5 par value, authorized 60,000,000 shares, 29,402,054 shares outstanding 147,010 147,010 
Other paid-in-capital 178,170 178,181 
Common stock, $5 par value, authorized 60,000,000 shares- 29,402,054 shares outstanding 147,010 147,010 
Other paid-in capital 178,122 178,182 
Accumulated other comprehensive loss  (48,179)  (49,803)  (47,620)  (49,183)
Retained earnings 112,310 214,490  108,379 117,534 
          
Total common stockholders’ equity 389,311 489,878  385,891 393,543 
Noncontrolling interest 2,587 2,696  2,591 2,589 
          
Total equity 391,898 492,574  388,482 396,132 
Long-term debt and other long-term obligations 600,478 600,443  600,508 600,493 
     
      988,990 996,625 
 992,376 1,093,017      
      
NONCURRENT LIABILITIES:
  
Accumulated deferred income taxes 116,090 80,508  157,797 132,019 
Accumulated deferred investment tax credits 6,039 6,367  5,822 5,930 
Retirement benefits 67,953 65,988  51,253 71,486 
Asset retirement obligations 28,287 32,290  29,245 28,762 
Lease market valuation liability 208,525 236,200  190,075 199,300 
Other 64,179 64,151  65,899 65,089 
          
 491,073 485,504  500,091 502,586 
          
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
 
COMMITMENTS AND CONTINGENCIES (Note 9)
 
 $1,598,062 $1,983,278  $1,661,396 $1,614,306 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

15

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
                
 Nine Months Ended  Three Months Ended 
 September 30  March 31 
 2010 2009 
 (In thousands) 
(In thousands) 2011 2010 
  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income $27,821 $14,497  $5,847 $7,509 
Adjustments to reconcile net income to net cash from operating activities-  
Provision for depreciation 23,763 23,136  7,931 7,950 
Amortization (deferral) of regulatory assets, net  (3,708) 30,921 
Deferral of regulatory assets, net  (11,478)  (8,499)
Deferred rents and lease market valuation liability  (36,123)  (34,556) 6,141 6,141 
Deferred income taxes and investment tax credits, net 18,927  (2,242) 25,046 11,287 
Accrued compensation and retirement benefits 4,529 3,039   (142) 837 
Accrued regulatory obligations  40  4,841 
Electric service prepayment programs —  (1,458)
Pension trust contribution —  (21,590)  (45,000) — 
Cash collateral from suppliers 9,874 2,830 
Decrease in operating assets- 
Decrease (increase) in operating assets- 
Receivables 61,051 24,561   (70,694) 45,376 
Prepayments and other current assets 2,839 109   (5,996)  (4,569)
Increase (decrease) in operating liabilities-  
Accounts payable  (69,846)  (13,440) 16,774  (35,414)
Accrued taxes  (6,172)  (5,057)  (1,358)  (4,933)
Accrued interest 10,050 14,033  10,052 10,050 
Other  (10,971)  (3,694) 6,098  (4,578)
          
Net cash provided from operating activities 32,074 35,930 
Net cash provided from (used for) operating activities  (56,779) 31,157 
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New Financing- 
Long-term debt — 297,422 
Redemptions and Repayments- 
Redemptions and repayments- 
Long-term debt  (167)  (292)  (56)  (56)
Short-term borrowings, net  (225,975)  (101,569) —  (225,975)
Common stock dividend payments  (130,000)  (25,000)  (15,000)  (130,000)
Other  (112)  (351) —  (2)
          
Net cash provided from (used for) financing activities  (356,254) 170,210 
Net cash used for financing activities  (15,056)  (356,033)
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (29,592)  (33,005)  (9,507)  (9,597)
Leasehold improvement payments from associated companies 32,829 — 
Loan repayments from associated companies, net 3,847 10,256 
Loan repayments from (loans to) associated companies, net 61,276  (33,587)
Redemptions of lessor notes 20,509 18,358  21,739 20,509 
Sales of investment securities held in trusts 118,360 171,061  13,883 31,067 
Purchases of investment securities held in trusts  (119,777)  (173,214)  (14,338)  (31,705)
Other  (4,550)  (2,776)  (466)  (1,227)
          
Net cash provided from (used for) investing activities 21,626  (9,320) 72,587  (24,540)
          
  
Net change in cash and cash equivalents  (302,554) 196,820  752  (349,416)
Cash and cash equivalents at beginning of period 436,712 14  149,262 436,712 
          
Cash and cash equivalents at end of period $134,158 $196,834  $150,014 $87,296 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

16

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                        
 Three Months Ended Nine Months Ended  Three Months Ended 
 September 30 September 30  March 31 
(In thousands) 2011 2010 
 2010 2009 2010 2009  
 (In thousands) 
STATEMENTS OF INCOME
 
REVENUES:
  
Electric sales $952,420 $854,108 $2,353,418 $2,312,089  $634,023 $691,392 
Excise tax collections 16,080 14,128 39,444 37,890  12,487 12,352 
              
Total revenues 968,500 868,236 2,392,862 2,349,979  646,510 703,744 
              
  
EXPENSES:
  
Purchased power 556,618 509,035 1,381,104 1,414,226  370,168 414,016 
Other operating expenses 89,167 84,495 260,004 241,241  86,079 95,660 
Provision for depreciation 26,614 26,565 81,678 76,969  25,314 27,971 
Amortization of regulatory assets, net 100,476 96,051 251,250 262,900  81,587 69,448 
General taxes 19,974 18,344 51,312 48,427  17,411 16,436 
              
Total expenses 792,849 734,490 2,025,348 2,043,763  580,559 623,531 
              
  
OPERATING INCOME
 175,651 133,746 367,514 306,216  65,951 80,213 
              
  
OTHER INCOME (EXPENSE):
  
Miscellaneous income 1,662 1,301 5,144 4,113  1,910 1,833 
Interest expense  (30,220)  (29,593)  (89,684)  (87,132)  (30,657)  (29,423)
Capitalized interest 199 139 488 419  427 133 
              
Total other expense  (28,359)  (28,153)  (84,052)  (82,600)  (28,320)  (27,457)
              
  
INCOME BEFORE INCOME TAXES
 147,292 105,593 283,462 223,616  37,631 52,756 
  
INCOME TAXES
 64,440 43,435 121,491 95,834  18,078 23,530 
              
  
NET INCOME
 82,852 62,158 161,971 127,782  $19,553 $29,226 
              
  
OTHER COMPREHENSIVE INCOME (LOSS):
 
STATEMENTS OF COMPREHENSIVE INCOME
 
 
NET INCOME
 $19,553 $29,226 
     
 
OTHER COMPREHENSIVE INCOME:
 
Pension and other postretirement benefits 4,135  (51,932) 24,198  (26,893) 4,221 15,928 
Unrealized gain on derivative hedges 69 69 207 207  69 69 
              
Other comprehensive income (loss) 4,204  (51,863) 24,405  (26,686)
Income tax expense (benefit) related to other comprehensive income 1,443  (21,295) 9,442  (8,806)
Other comprehensive income 4,290 15,997 
Income tax expense related to other comprehensive income 1,590 6,558 
              
Other comprehensive income (loss), net of tax 2,761  (30,568) 14,963  (17,880)
Other comprehensive income, net of tax 2,700 9,439 
              
  
TOTAL COMPREHENSIVE INCOME
 $85,613 $31,590 $176,934 $109,902 
COMPREHENSIVE INCOME
 $22,253 $38,665 
              
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

17

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                
 September 30, December 31,  March 31, December 31, 
 2010 2009 
 (In thousands) 
(In thousands) 2011 2010 
ASSETS
  
 
CURRENT ASSETS:
  
Cash and cash equivalents $1 $27  $1 $4 
Receivables-  
Customers (less accumulated provisions of $4,736,000 and $3,506,000, respectively, for uncollectible accounts) 378,822 300,991 
Customers (net of allowance for uncollectible accounts of $3,842 in 2011 and $3,769 in 2010) 268,171 323,044 
Associated companies 3,900 12,884  27,144 53,780 
Other 26,024 21,877  21,269 26,119 
Notes receivable — associated companies 64,168 102,932  298,274 177,228 
Prepaid taxes 71,153 34,930  10,968 10,889 
Other 15,674 12,945  16,357 12,654 
          
 559,742 486,586  642,184 603,718 
          
UTILITY PLANT:
  
In service 4,568,640 4,463,490  4,579,753 4,562,781 
Less — Accumulated provision for depreciation 1,666,918 1,617,639  1,667,017 1,656,939 
          
 2,901,722 2,845,851  2,912,736 2,905,842 
Construction work in progress 51,857 54,251  78,819 63,535 
          
 2,953,579 2,900,102  2,991,555 2,969,377 
          
OTHER PROPERTY AND INVESTMENTS:
  
Nuclear fuel disposal trust 206,833 207,561 
Nuclear plant decommissioning trusts 175,254 166,768  190,424 181,851 
Nuclear fuel disposal trust 208,870 199,677 
Other 2,136 2,149  2,111 2,104 
          
 386,260 368,594  399,368 391,516 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Goodwill 1,810,936 1,810,936  1,810,936 1,810,936 
Regulatory assets 722,086 888,143  460,156 513,395 
Other 30,608 27,096  25,243 27,938 
          
 2,563,630 2,726,175  2,296,335 2,352,269 
          
 $6,463,211 $6,481,457  $6,329,442 $6,316,880 
          
LIABILITIES AND CAPITALIZATION
  
 
CURRENT LIABILITIES:
  
Currently payable long-term debt $31,947 $30,639  $32,855 $32,402 
Accounts payable-  
Associated companies 12,743 26,882  16,983 28,571 
Other 154,872 168,093  123,814 158,442 
Accrued compensation and benefits 33,415 35,232 
Customer deposits 23,494 23,385 
Accrued taxes 24,798 12,594  15,142 2,509 
Accrued interest 30,003 18,256  29,926 18,111 
Other 78,903 111,156  25,663 22,263 
          
 333,266 367,620  301,292 320,915 
          
CAPITALIZATION:
  
Common stockholders’ equity-  
Common stock, $10 par value, authorized 16,000,000 shares, 13,628,447 shares outstanding 136,284 136,284 
Common stock, $10 par value, authorized 16,000,000 shares- 13,628,447 shares outstanding 136,284 136,284 
Other paid-in capital 2,508,852 2,507,049  2,508,754 2,508,874 
Accumulated other comprehensive loss  (228,049)  (243,012)  (250,842)  (253,542)
Retained earnings 197,046 200,075  246,723 227,170 
          
Total common stockholders’ equity 2,614,133 2,600,396 
Total common stockholder’s equity 2,640,919 2,618,786 
Long-term debt and other long-term obligations 1,779,081 1,801,589  1,762,365 1,769,849 
          
 4,393,214 4,401,985  4,403,284 4,388,635 
          
NONCURRENT LIABILITIES:
  
Accumulated deferred income taxes 720,825 687,545  729,478 715,527 
Power purchase contract liability 238,677 233,492 
Nuclear fuel disposal costs 196,703 196,511  196,843 196,768 
Retirement benefits 133,579 150,603  175,175 182,364 
Asset retirement obligations 106,573 101,568  110,050 108,297 
Power purchase contract liability 386,273 399,105 
Other 192,778 176,520  174,643 170,882 
          
 1,736,731 1,711,852  1,624,866 1,607,330 
          
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
  
 $6,463,211 $6,481,457  $6,329,442 $6,316,880 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

18

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
                
 Nine Months Ended  Three Months Ended 
 September 30  March 31 
 2010 2009 
 (In thousands) 
(In thousands) 2011 2010 
  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income $161,971 $127,782  $19,553 $29,226 
Adjustments to reconcile net income to net cash from operating activities-  
Provision for depreciation 81,678 76,969  25,314 27,971 
Amortization of regulatory assets, net 251,250 262,900  81,587 69,448 
Deferred purchased power and other costs  (85,136)  (106,340)  (26,516)  (32,775)
Deferred income taxes and investment tax credits, net 14,984 40,989  25,560  (2,082)
Accrued compensation and retirement benefits 11,621 7,308   (4,776)  (5,847)
Cash collateral paid, net  (23,400)  (210)
Pension trust contribution —  (100,000)
Cash collateral returned to suppliers  (250)  (23,400)
Decrease (increase) in operating assets-  
Receivables  (72,994) 18,984  86,359 33,257 
Prepayments and other current assets  (36,573)  (83,538)  (1,687) 16,472 
Increase (decrease) in operating liabilities-  
Accounts payable  (37,668)  (40,670)  (61,612)  (40,992)
Accrued taxes 35,326  (13,399) 12,631 50,857 
Accrued interest 11,747 20,946  11,815 11,816 
Tax collections payable —  (9,714) 7,084 14,544 
Other  (13,953) 12,606  7,448 466 
          
Net cash provided from operating activities 298,853 214,613  182,510 148,961 
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New Financing- 
Redemptions and repayments- 
Long-term debt — 299,619   (7,190)  (6,773)
Redemptions and Repayments- 
Common stock —  (150,000)
Long-term debt  (21,703)  (20,570)
Short-term borrowings, net —  (114,766)
Common stock dividend payments  (165,000)  (88,000) —  (90,000)
Other  (2)  (2,275)
          
Net cash used for financing activities  (186,705)  (75,992)  (7,190)  (96,773)
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (130,008)  (121,342)  (47,604)  (37,338)
Loans from (to) associated companies, net 38,764  (660)
Loans to associated companies, net  (121,046)  (7,620)
Sales of investment securities held in trusts 340,368 338,684  217,103 190,198 
Purchases of investment securities held in trusts  (353,028)  (351,216)  (221,695)  (194,748)
Other  (8,270)  (4,152)  (2,081)  (2,706)
          
Net cash used for investing activities  (112,174)  (138,686)  (175,323)  (52,214)
          
  
Net change in cash and cash equivalents  (26)  (65)  (3)  (26)
Cash and cash equivalents at beginning of period 27 66  4 27 
          
Cash and cash equivalents at end of period $1 $1  $1 $1 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

19

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                        
 Three Months Ended Nine Months Ended  Three Months Ended 
 September 30 September 30  March 31 
(In thousands) 2011 2010 
 2010 2009 2010 2009  
STATEMENTS OF INCOME
 
 (In thousands)  
REVENUES:
  
Electric sales $460,864 $424,901 $1,334,454 $1,194,609  $338,416 $451,560 
Gross receipts tax collections 23,049 20,612 65,245 58,181  18,800 21,567 
              
Total revenues 483,913 445,513 1,399,699 1,252,790  357,216 473,127 
              
  
EXPENSES:
  
Purchased power from affiliates 166,039 94,768 476,119 273,497  49,889 161,080 
Purchased power from non-affiliates 87,561 142,495 264,765 389,705  153,043 91,928 
Other operating expenses 141,761 63,654 333,895 221,320  47,232 101,983 
Provision for depreciation 12,978 13,262 39,176 38,320  12,423 12,758 
Amortization of regulatory assets, net 15,480 84,631 112,869 173,770  32,094 48,800 
General taxes 25,029 22,540 66,663 66,509  22,150 21,740 
              
Total expenses 448,848 421,350 1,293,487 1,163,121  316,831 438,289 
              
  
OPERATING INCOME
 35,065 24,163 106,212 89,669  40,385 34,838 
              
  
OTHER INCOME (EXPENSE):
  
Interest income 581 2,169 2,678 8,124  93 1,217 
Miscellaneous income 1,539 1,068 5,093 2,982  970 2,173 
Interest expense  (13,037)  (14,380)  (39,812)  (42,502)  (13,057)  (13,773)
Capitalized interest 176 47 461 124  147 126 
              
Total other expense  (10,741)  (11,096)  (31,580)  (31,272)  (11,847)  (10,257)
              
  
INCOME BEFORE INCOME TAXES
 24,324 13,067 74,632 58,397  28,538 24,581 
  
INCOME TAXES
 10,084 2,324 30,968 21,027  5,951 12,266 
              
  
NET INCOME
 14,240 10,743 43,664 37,370  $22,587 $12,315 
              
  
OTHER COMPREHENSIVE INCOME (LOSS):
 
STATEMENTS OF COMPREHENSIVE INCOME
 
 
NET INCOME
 $22,587 $12,315 
     
 
OTHER COMPREHENSIVE INCOME:
 
Pension and other postretirement benefits 2,161  (31,365) 14,032 557  1,963 9,709 
Unrealized gain on derivative hedges 84 84 252 252  84 84 
              
Other comprehensive income (loss) 2,245  (31,281) 14,284 809 
Income tax expense (benefit) related to other comprehensive income 723  (13,112) 5,624 2,273 
Other comprehensive income 2,047 9,793 
Income tax expense related to other comprehensive income 763 4,177 
              
Other comprehensive income (loss), net of tax 1,522  (18,169) 8,660  (1,464)
Other comprehensive income, net of tax 1,284 5,616 
              
  
TOTAL COMPREHENSIVE INCOME (LOSS)
 $15,762 $(7,426) $52,324 $35,906 
COMPREHENSIVE INCOME
 $23,871 $17,931 
              
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

20

METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                
 September 30, December 31,  March 31, December 31, 
 2010 2009 
(In thousands) 2011 2010 
 (In thousands)  
ASSETS
  
  
CURRENT ASSETS:
  
Cash and cash equivalents $124 $120  $117 $243,220 
Receivables-  
Customers (less accumulated provisions of $4,344,000 and $4,044,000, respectively, for uncollectible accounts) 182,509 171,052 
Customers (less allowance for doubtful accounts of $3,841 in 2011 and $3,868 in 2010, respectively) 159,801 178,522 
Associated companies 41,689 29,413  23,110 24,920 
Other 13,654 11,650  16,836 13,007 
Notes receivable from associated companies 11,201 97,150  9,542 11,028 
Prepaid taxes 27,307 15,229  40,883 343 
Other 2,523 1,459  1,973 2,289 
          
 279,007 326,073  252,262 473,329 
          
UTILITY PLANT:
  
In service 2,213,765 2,162,815  2,260,156 2,247,853 
Less — Accumulated provision for depreciation 836,821 810,746  852,326 846,003 
          
 1,376,944 1,352,069  1,407,830 1,401,850 
Construction work in progress 31,488 14,901  27,714 23,663 
          
 1,408,432 1,366,970  1,435,544 1,425,513 
          
OTHER PROPERTY AND INVESTMENTS:
  
Nuclear plant decommissioning trusts 277,823 266,479  303,906 289,328 
Other 877 890  881 884 
          
 278,700 267,369  304,787 290,212 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Goodwill 416,499 416,499  416,499 416,499 
Regulatory assets 400,375 356,754  285,300 295,856 
Power purchase contract asset 103,902 176,111  107,055 111,562 
Other 64,084 36,544  51,939 31,699 
          
 984,860 985,908  860,793 855,616 
          
 $2,950,999 $2,946,320  $2,853,386 $3,044,670 
          
LIABILITIES AND CAPITALIZATION
  
  
CURRENT LIABILITIES:
  
Currently payable long-term debt $28,500 $128,500  $42,450 $28,760 
Short-term borrowings-  
Associated companies 6,296 —  109,709 124,079 
Accounts payable-  
Associated companies 34,204 40,521  35,758 33,942 
Other 28,604 41,050  47,450 29,862 
Accrued taxes 2,967 11,170  14,514 60,856 
Accrued interest 11,717 17,362  11,738 16,114 
Other 31,993 24,520  29,543 29,278 
          
 144,281 263,123  291,162 322,891 
          
CAPITALIZATION:
  
Common stockholders’ equity-  
Common stock, without par value, authorized 900,000 shares, 859,500 shares outstanding 1,197,064 1,197,070 
Common stock, without par value, authorized 900,000 shares- 740,905 shares outstanding 1,046,970 1,197,076 
Accumulated other comprehensive loss  (134,891)  (143,551)  (141,099)  (142,383)
Retained earnings 48,064 4,399  29,994 32,406 
          
Total common stockholders’ equity 1,110,237 1,057,918 
Total common stockholder’s equity 935,865 1,087,099 
Long-term debt and other long-term obligations 713,941 713,873  705,125 718,860 
          
 1,824,178 1,771,791  1,640,990 1,805,959 
          
NONCURRENT LIABILITIES:
  
Accumulated deferred income taxes 489,608 453,462  481,530 473,009 
Accumulated deferred investment tax credits 6,978 7,313  6,761 6,866 
Nuclear fuel disposal costs 44,434 44,391  44,465 44,449 
Asset retirement obligations 195,883 192,659 
Retirement benefits 28,268 33,605  22,405 29,121 
Asset retirement obligations 189,489 180,297 
Power purchase contract liability 175,259 143,135  118,123 116,027 
Other 48,504 49,203  52,067 53,689 
          
 982,540 911,406  921,234 915,820 
          
COMMITMENTS AND CONTINGENCIES (Note 9)
  
 $2,950,999 $2,946,320  $2,853,386 $3,044,670 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

21

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
                
 Nine Months Ended  Three Months Ended 
 September 30  March 31 
 2010 2009 
 (In thousands) 
(In thousands) 2011 2010 
  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income $43,664 $37,370  $22,587 $12,315 
Adjustments to reconcile net income to net cash from operating activities-  
Provision for depreciation 39,176 38,320  12,423 12,758 
Amortization of regulatory assets, net 112,869 173,770  32,094 48,800 
Deferred costs recoverable as regulatory assets  (49,646)  (70,044)  (12,082)  (18,276)
Deferred income taxes and investment tax credits, net 23,781 59,393  1,304  (10,308)
Accrued compensation and retirement benefits  (282) 6,712   (1,433)  (2,527)
Pension trust contribution —  (123,521)
Cash collateral paid, net  (17,647)  (6,800)
Cash collateral returned from (paid to) suppliers 1,000  (700)
Pension trust contributions  (35,000) — 
Decrease (increase) in operating assets-  
Receivables  (18,444)  (23,370) 16,702  (5,083)
Prepayments and other current assets  (13,144)  (22,614)  (40,225)  (52,040)
Increase (decrease) in operating liabilities-  
Accounts payable  (18,763)  (17,293) 15,749  (7,279)
Accrued taxes  (8,203)  (11,095)  (46,006) 19,960 
Accrued interest  (5,645) 5,001   (4,376)  (5,674)
Other 7,721 11,891  6,337 2,373 
          
Net cash provided from operating activities 95,437 57,720 
Net cash used for operating activities  (30,926)  (5,681)
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New Financing- 
New financing- 
Short-term borrowings, net — 48,793 
Redemptions and repayments- 
Long-term debt — 300,000  —  (100,000)
Short-term borrowings, net 6,296 —   (14,369) — 
Redemptions and Repayments- 
Long-term debt  (100,000) — 
Short-term borrowings, net —  (265,003)
Other —  (2,268)
Common stock  (150,000) — 
Common stock dividend payments  (25,000) — 
          
Net cash provided from (used for) financing activities  (93,704) 32,729 
Net cash used for financing activities  (189,369)  (51,207)
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (77,921)  (73,106)  (21,126)  (25,526)
Sales of investment securities held in trusts 420,116 88,802  335,860 143,713 
Purchases of investment securities held in trusts  (427,150)  (95,982)  (337,632)  (146,056)
Loans from (to) associated companies, net 85,949  (6,586)
Loans repayments from associated companies, net 1,486 85,383 
Other  (2,723)  (3,597)  (1,396)  (618)
          
Net cash used for investing activities  (1,729)  (90,469)
Net cash provided from (used for) investing activities  (22,808) 56,896 
          
  
Net change in cash and cash equivalents 4  (20)
Net increase (decrease) in cash and cash equivalents  (243,103) 8 
Cash and cash equivalents at beginning of period 120 144  243,220 120 
          
Cash and cash equivalents at end of period $124 $124  $117 $128 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

22

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                        
 Three Months Ended Nine Months Ended  Three Months Ended 
 September 30 September 30  March 31 
(In thousands) 2011 2010 
 2010 2009 2010 2009  
 (In thousands) 
STATEMENTS OF INCOME
 
REVENUES:
  
Electric sales $372,480 $340,246 $1,108,751 $1,028,420  $308,316 $385,936 
Gross receipts tax collections 17,414 15,246 51,100 47,342  16,529 17,524 
              
Total revenues 389,894 355,492 1,159,851 1,075,762  324,845 403,460 
              
  
EXPENSES:
  
Purchased power from affiliates 165,125 81,191 486,470 249,438  47,484 168,400 
Purchased power from non-affiliates 92,648 144,777 270,900 397,260  141,436 91,423 
Other operating expenses 58,832 47,785 198,296 171,375  41,328 72,394 
Provision for depreciation 14,859 15,038 46,146 45,074  14,573 14,682 
Amortization (deferral) of regulatory assets, net  (1,771) 17,201  (22,259) 44,090  13,007  (9,966)
General taxes 19,194 17,230 54,375 56,074  20,736 16,534 
              
Total expenses 348,887 323,222 1,033,928 963,311  278,564 353,467 
              
  
OPERATING INCOME
 41,007 32,270 125,923 112,451  46,281 49,993 
              
  
OTHER INCOME (EXPENSE):
  
Miscellaneous income 1,508 1,156 4,431 2,865  25 1,613 
Interest expense  (17,581)  (11,614)  (52,501)  (36,690)  (17,234)  (17,290)
Capitalized interest 193 23 516 74  22 140 
              
Total other expense  (15,880)  (10,435)  (47,554)  (33,751)  (17,187)  (15,537)
              
  
INCOME BEFORE INCOME TAXES
 25,127 21,835 78,369 78,700  29,094 34,456 
  
INCOME TAXES
 5,311 6,039 28,280 29,393  11,788 17,157 
              
  
NET INCOME
 19,816 15,796 50,089 49,307  $17,306 $17,299 
              
  
OTHER COMPREHENSIVE INCOME (LOSS):
 
STATEMENTS OF COMPREHENSIVE INCOME
 
 
NET INCOME
 $17,306 $17,299 
     
 
OTHER COMPREHENSIVE INCOME:
 
Pension and other postretirement benefits 1,830  (79,579) 12,207  (47,224) 1,585 8,547 
Unrealized gain on derivative hedges 16 17 48 49  16 16 
Change in unrealized gain on available-for-sale securities — 19 — 3 
              
Other comprehensive income (loss) 1,846  (79,543) 12,255  (47,172)
Income tax expense (benefit) related to other comprehensive income 484  (33,141) 4,251  (16,986)
Other comprehensive income 1,601 8,563 
Income tax expense related to other comprehensive income 555 3,284 
              
Other comprehensive income (loss), net of tax 1,362  (46,402) 8,004  (30,186)
Other comprehensive income, net of tax 1,046 5,279 
              
  
TOTAL COMPREHENSIVE INCOME (LOSS)
 $21,178 $(30,606) $58,093 $19,121 
COMPREHENSIVE INCOME
 $18,352 $22,578 
              
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

23

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                
 September 30, December 31,  March 31, December 31, 
 2010 2009 
(In thousands) 2011 2010 
 (In thousands)  
ASSETS
  
  
CURRENT ASSETS:
  
Cash and cash equivalents $8 $14  $3 $5 
Receivables-  
Customers (less accumulated provisions of $3,481,000 and $3,483,000, respectively, for uncollectible accounts) 135,416 139,302 
Customers (net of allowance for uncollectible accounts of $3,395 in 2011 and $3,369 in 2010) 139,058 148,864 
Associated companies 95,355 77,338  16,921 54,052 
Other 14,413 18,320  12,142 11,314 
Notes receivable from associated companies 14,569 14,589  12,334 14,404 
Prepaid taxes 48,264 18,946  47,126 14,026 
Other 2,115 1,400  1,843 1,592 
          
 310,140 269,909  229,427 244,257 
          
UTILITY PLANT:
  
In service 2,503,555 2,431,737  2,545,211 2,532,629 
Less — Accumulated provision for depreciation 925,894 901,990  939,247 935,259 
          
 1,577,661 1,529,747  1,605,964 1,597,370 
Construction work in progress 28,498 24,205  40,799 30,505 
          
 1,606,159 1,553,952  1,646,763 1,627,875 
          
OTHER PROPERTY AND INVESTMENTS:
  
Nuclear plant decommissioning trusts 147,675 142,603  159,999 152,928 
Non-utility generation trusts 92,034 120,070  80,275 80,244 
Other 294 289  294 297 
          
 240,003 262,962  240,568 233,469 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Goodwill 768,628 768,628  768,628 768,628 
Regulatory assets 202,801 9,045  179,092 163,407 
Power purchase contract asset 5,746 15,362  4,169 5,746 
Other 28,780 19,143  15,140 19,287 
          
 1,005,955 812,178  967,029 957,068 
          
 $3,162,257 $2,899,001  $3,083,787 $3,062,669 
          
LIABILITIES AND CAPITALIZATION
  
  
CURRENT LIABILITIES:
  
Currently payable long-term debt $69,310 $69,310  $45,000 $45,000 
Short-term borrowings-  
Associated companies 43,244 41,473  90,363 101,338 
Accounts payable-  
Associated companies 40,747 39,884  41,231 35,626 
Other 28,427 41,990  33,125 41,420 
Accrued taxes 4,164 6,409  4,262 5,075 
Accrued interest 24,513 17,598  24,069 17,378 
Other 25,871 22,741  23,467 22,541 
          
 236,276 239,405  261,517 268,378 
          
CAPITALIZATION:
  
Common stockholders’ equity-  
Common stock, $20 par value, authorized 5,400,000 shares, 4,427,577 shares outstanding 88,552 88,552 
Common stock, $20 par value, authorized 5,400,000 shares- 4,427,577 shares outstanding 88,552 88,552 
Other paid-in capital 913,507 913,437  913,439 913,519 
Accumulated other comprehensive loss  (154,100)  (162,104)  (162,480)  (163,526)
Retained earnings 141,590 91,501  58,299 60,993 
          
Total common stockholders’ equity 989,549 931,386 
Total common stockholder’s equity 897,810 899,538 
Long-term debt and other long-term obligations 1,072,207 1,072,181  1,072,339 1,072,262 
          
 2,061,756 2,003,567  1,970,149 1,971,800 
          
NONCURRENT LIABILITIES:
  
Accumulated deferred income taxes 356,536 242,040  393,088 371,877 
Retirement benefits 167,542 174,306  187,888 187,621 
Power purchase contract liability 121,558 116,972 
Asset retirement obligations 96,519 91,841  99,773 98,132 
Power purchase contract liability 194,102 100,849 
Other 49,526 46,993  49,814 47,889 
          
 864,225 656,029  852,121 822,491 
          
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
  
 $3,162,257 $2,899,001  $3,083,787 $3,062,669 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

24

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
                
 Nine Months Ended  Three Months Ended 
 September 30  March 31 
 2010 2009 
 (In thousands) 
(In thousands) 2011 2010 
  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income $50,089 $49,307  $17,306 $17,299 
Adjustments to reconcile net income to net cash from operating activities-  
Provision for depreciation 46,146 45,074  14,573 14,682 
Amortization (deferral) of regulatory assets, net  (22,259) 44,090  13,007  (9,966)
Deferred costs recoverable as regulatory assets  (61,574)  (76,953)  (17,771)  (20,461)
Deferred income taxes and investment tax credits, net 94,015 56,144  16,648 21,772 
Accrued compensation and retirement benefits 7,634 6,271  1,551  (169)
Cash collateral paid, net  (11,760) —   (2,124)  (400)
Pension trust contribution —  (60,000)
Decrease (increase) in operating assets-  
Receivables  (2,584) 3,687  46,100  (4,641)
Prepayments and other current assets  (30,034)  (24,730)  (33,350)  (50,186)
Increase (decrease) in operating liabilities-  
Accounts payable  (12,766)  (8,988)  (8,534)  (1,348)
Accrued taxes  (2,245)  (7,015)  (813)  (2,142)
Accrued interest 6,915  (2,570) 6,691 6,882 
Other 10,127 13,392  10,204 7,162 
          
Net cash provided from operating activities 71,704 37,709 
Net cash provided from (used for) operating activities 63,488  (21,516)
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New Financing- 
Long-term debt — 498,583 
New financing- 
Short-term borrowings, net 1,771 —  — 51,334 
Redemptions and Repayments- 
Long-term debt —  (100,000)
Redemptions and repayments- 
Short-term borrowings, net —  (239,770)  (10,975) — 
Common stock dividend payments —  (85,000)  (20,000) — 
Other  (125)  (3,865) 26  (6)
          
Net cash provided from financing activities 1,646 69,948 
Net cash provided from (used for) financing activities  (30,949) 51,328 
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (91,924)  (92,070)  (31,128)  (27,388)
Loan repayments from associated companies, net 2,070 279 
Sales of investment securities held in trusts 141,392 80,986  178,927 93,057 
Purchases of investment securities held in trusts  (116,240)  (91,105)  (180,411)  (94,464)
Other  (6,584)  (5,482)  (1,999)  (1,298)
          
Net cash used for investing activities  (73,356)  (107,671)  (32,541)  (29,814)
          
  
Net change in cash and cash equivalents  (6)  (14)  (2)  (2)
Cash and cash equivalents at beginning of period 14 23  5 14 
          
Cash and cash equivalents at end of period $8 $9  $3 $12 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

25

COMBINED NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
1. ORGANIZATION AND BASIS OF PRESENTATION
FirstEnergy is a diversified energy company that holds, directly or indirectly, all of the outstanding common stock of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), ATSI, JCP&L, Met-Ed, Penelec, FENOC, AE and its principal subsidiaries (AE Supply, AGC, MP, PE, WP and TrAIL Company), FES and its subsidiaries FGCO and NGC, and FESC. AE merged with a subsidiary of FirstEnergy on February 25, 2011, with AE remaining as the surviving corporation and becoming a wholly-owned subsidiary of FirstEnergy (See Note 2, Merger).
FirstEnergy and its subsidiaries follow GAAP and comply with the regulations, orders, policies and practices prescribed by the SEC, the FERC, the NERC and, as applicable, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC and the NJBPU. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not indicative of results of operations for any future period. In preparing the financial statements, FirstEnergy and its subsidiaries have evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued.
These statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K for the year ended December 31, 20092010 for FirstEnergy, FES and the Utilities,Utility Registrants, as applicable.applicable, and the Current Report on Form 8-K filed by FirstEnergy on February 25, 2011, as amended on April 19, 2011. The consolidated unaudited financial statements of FirstEnergy, FES and each of the UtilitiesUtility Registrants reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain prior year amounts have been reclassified to conform to the current year presentation. Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.
FirstEnergy and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary (see Note 7)7, Variable Interest Entities). Investments in affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but with respect to which are not the primary beneficiary and do not exercise control, follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage share of the entity’s earnings is reported in the Consolidated Statements of Income.
2. MERGER
Merger
On February 25, 2011, the merger between FirstEnergy and Allegheny closed. Pursuant to the terms of the Agreement and Plan of Merger among FirstEnergy, Element Merger Sub, Inc., a Maryland corporation and a wholly-owned subsidiary of FirstEnergy (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 FirstEnergy. As part of the merger, AE shareholders received 0.667 of a share of FirstEnergy 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 FirstEnergy equity-based awards on the same basis.
The merger created a combined company with increased scale and scope and greater diversification in energy delivery, generation and transmission. The combined company is the largest U.S. diversified electric utility by customers and operates one of the largest unregulated power generation fleets in the United States with FirstEnergy’s total current capacity of approximately 23,000 MW, which includes approximately 3,000 MW of regulated generation.

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The total consideration in the merger was based on the closing price of a share of FirstEnergy 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 Allegheny common stock outstanding on February 24, 2011  170 
Exchange ratio  0.667 
    
Number of shares of FirstEnergy common stock issued  113 
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 service  27 
    
Total consideration transferred $4,354 
    
The preliminary allocation of the total consideration transferred to the assets acquired and liabilities assumed includes adjustments for the fair value of coal contracts, energy supply contracts, emission allowances, unregulated property, plant and equipment, derivative instruments, goodwill, intangible assets, long-term debt and deferred income taxes. The preliminary allocation of the purchase price is as follows:
     
  Preliminary 
  Purchase Price 
(In millions) Allocation 
     
Current assets $1,509 
Property, plant and equipment  9,656 
Investments  138 
Goodwill  952 
Other noncurrent assets  1,262 
Current liabilities  (714)
Noncurrent liabilities  (3,453)
Long-term debt and other long-term obligations  (4,996)
    
  $4,354 
    
Assumptions and estimates underlying the fair value adjustments are subject to change pending further review of the assets acquired and liabilities assumed.
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 generation businesses have been assigned to the Regulated Distribution, Regulated Independent Transmission and Competitive Energy Services segments, respectively. The preliminary estimate of goodwill from the merger of $952 million was assigned entirely to the Competitive Energy Services segment based on expected synergies from the merger. The goodwill is not deductible for tax purposes.
Total goodwill recognized by segment in FirstEnergy’s Consolidated Balance Sheet is as follows:
                     
      Competitive  Regulated       
  Regulated  Energy  Independent  Other/    
(In millions) Distribution  Services  Transmission  Corporate  Consolidated 
                     
Balance at December 31, 2010 $5,551  $24  $—  $—  $5,575 
                     
Merger with Allegheny  —   952   —   —   952 
                
                     
Balance at March 31, 2011 $5,551  $976  $—  $—  $6,527 
                
                    

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The preliminary valuation of the additional intangible assets and liabilities recorded as result of the merger is as follows:
         
  Preliminary  Weighted Average 
(In millions) Valuation  Amortization Period 
Above market contracts:        
Energy supply contracts $189  10 years
NUG contracts  124  25 years
Coal supply contracts  525  8 years
        
   838     
         
Below market contracts:        
NUG contracts  143  13 years
Coal supply contracts  86  7 years
Transportation contract  35  8 years
        
   264     
        
         
  $574     
        
The fair value measurements of intangible assets and liabilities were primarily 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 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 based on the present value of the above/below market cash flows attributable to the contracts. The fair value of these contracts will be amortized based on expected deliveries under each contract.
Total intangible assets recorded on FirstEnergy’s Consolidated Balance Sheet as of March 31, 2011 are as follows:
     
  Intangible 
(In millions) Assets 
Purchase contract assets    
NUG $241 
OVEC  52 
    
   293 
     
Intangible assets    
Coal contracts  520 
FES customer intangible assets  132 
Energy contracts  130 
    
   782 
    
     
  $1,075 
    
Other intangible assets acquired in the Allegheny merger include land easements and software, having a fair value of $126 million, are included in “Property, plant and equipment” on FirstEnergy’s Consolidated Balance Sheet as of March 31, 2011.
In connection with the merger, FirstEnergy recorded approximately $82 million ($68 million net of tax) and $14 million ($10 million net of tax) of merger transaction costs during the first quarter of 2011 and 2010, respectively. These costs are included in “Other operating expenses” in the Consolidated Statement of Income. Merger transaction costs recognized in the first quarter of 2011 include $56 million ($47 net of tax) of change in control and other benefit payments to AE executives.

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FirstEnergy also recorded approximately $75 million in merger integration costs during the first quarter of 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 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).
The amounts of revenue and earnings of Allegheny since the merger date included in FirstEnergy’s Consolidated Statement of Income for the quarter ended March 31, 2011 are as follows:
     
  February 26 - 
(In millions, except per share amounts) March 31, 2011 
     
Total revenues $437 
Net Income(1)
  (46)
     
Basic Earnings Per Share $(0.13)
Diluted Earnings Per Share $(0.13)
(1)Includes Allegheny’s after-tax merger costs of $52 million.
Pro Forma Financial Information
The following unaudited pro forma financial information reflects the consolidated results of operations of FirstEnergy as if the merger with Allegheny had taken place on January 1, 2010. The unaudited pro forma information has been 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 non-recurring costs directly related to the merger that have been included in the pro forma earnings presented below. Approximately $83 million and $27 million of combined pre-tax transaction costs were incurred in the three months ended March 31, 2011 and March 31, 2010, respectively. In addition, in the three months ended March 31, 2011, $75 million of pre-tax merger integration costs and $24 million of charges from merger settlements approved by regulatory agencies have been recognized. Charges resulting from merger settlements are not expected to be material in future periods.
The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the pro forma events taken place on the dates indicated, or the future consolidated results of operations of the combined company.
         
  Three Months Ended 
  March 31 
(Pro forma amounts in millions, except per share amounts) 2011  2010 
         
Revenues $4,786  $4,685 
Net income attributable to FirstEnergy $137  $255 
         
Basic Earnings Per Share $0.33  $0.61 
       
Diluted Earnings Per Share $0.33  $0.61 
       

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3. EARNINGS PER SHARE
Basic earnings per share of common stock isare computed using the weighted average 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 resultwould be issued if dilutive securities and other agreements to issue common stock were exercised. The following table reconciles basic and diluted earnings per share of common stock:
                        
 Three Months Nine Months  Three Months Ended 
Reconciliation of Basic and Diluted Earnings per Share Ended September 30 Ended September 30 
of Common Stock 2010 2009 2010 2009 
Reconciliation of Basic and Diluted March 31 
Earnings per Share of Common Stock 2011 2010 
 (In millions, except per 
 (In millions, except per share amounts)  share amounts) 
  
Earnings available to FirstEnergy Corp. $179 $234 $599 $768  $50 $155 
              
  
Weighted average number of basic shares outstanding 304 304 304 304 
Weighted average number of basic shares outstanding(1)
 342 304 
Assumed exercise of dilutive stock options and awards 1 2 1 2  1 2 
              
Weighted average number of diluted shares outstanding 305 306 305 306 
Weighted average number of diluted shares outstanding(1)
 343 306 
              
  
Basic earnings per share of common stock $0.59 $0.77 $1.97 $2.52  $0.15 $0.51 
              
Diluted earnings per share of common stock $0.59 $0.77 $1.96 $2.51  $0.15 $0.51 
              

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3. 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 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. 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.
FirstEnergy’s goodwill primarily relates to its energy delivery services segment. FirstEnergy’s aggregated reporting units are consistent with its operating segments, which are energy delivery services and competitive energy. Goodwill is allocated to these operating segments based on the original purchase price allocation for acquisitions within the various reporting units. The goodwill allocated to competitive energy is insignificant to that segment and to FirstEnergy.
Annual impairment testing is conducted during the third quarter of each year and for 2010 the analysis indicated no impairment of goodwill. For purposes of annual testing the estimated fair values of energy delivery services and the utilities were determined using a discounted cash flow approach.
The discounted cash flow model of the reporting units, which are aggregated into operating segments, is based on the forecasted operating cash flow for the current year, projected operating cash flows for the next five years (determined using forecasted amounts as well as an estimated growth rate) and a terminal value beyond five years. 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 working capital, projected capital expenditures, planned funding of pension plans, anticipated funding of nuclear decommissioning trusts, expected results of future rate proceedings and a discount rate equal to our assumed long term cost of capital. Cash flows may be adjusted to exclude certain non-recurring or unusual items. Reporting unit income, which excludes non-recurring or unusual items, 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.
Unanticipated changes in assumptions could have a significant effect on FirstEnergy’s evaluation of goodwill. At the time of annual impairment testing, fair value would have to have declined in excess of 52% for energy delivery services to indicate a potential goodwill impairment. Fair value would have to have declined more than 26% for CEI, 64% for TE, 38% for JCP&L, 56% for Met-Ed, and 57% for Penelec to indicate potential goodwill impairment.

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(1)Includes 113 million shares issued to AE stockholders for the period subsequent to the merger date. (See Note 2, Merger)
4. FAIR VALUE OF FINANCIAL INSTRUMENTS
(A) LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS
All borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are reported on the Consolidated Balance Sheets at cost, which approximates their fair market value, in the caption “short-term borrowings.” The following table provides the approximate fair value and related carrying amounts of long-term debt and other long-term obligations as of September 30, 2010March 31, 2011 and December 31 2009:2010:
                                
 September 30, 2010 December 31, 2009  March 31, 2011 December 31, 2010 
 Carrying Fair Carrying Fair  Carrying Fair Carrying Fair 
 Value Value Value Value  Value Value Value Value 
 (In millions)  (In millions) 
 
FirstEnergy (Consolidated) $13,592 $14,920 $13,753 $14,502 
FirstEnergy(1)
 $18,743 $19,776 $13,928 $14,845 
FES 4,181 4,228 4,224 4,306  4,099 4,227 4,279 4,403 
OE 1,159 1,409 1,169 1,299  1,159 1,334 1,159 1,321 
CEI 1,853 2,144 1,873 2,032  1,831 2,035 1,853 2,035 
TE 600 706 600 638  600 666 600 653 
JCP&L 1,819 2,076 1,840 1,950  1,802 1,980 1,810 1,962 
Met-Ed 742 849 842 909  742 826 742 821 
Penelec 1,144 1,269 1,144 1,177  1,120 1,190 1,120 1,189 
(1)Includes debt assumed in the Allegheny merger (See Note 2) with a carrying value and a fair value as of March 31, 2011 of $4,995 million and $5,004 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 securitiesobligations 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 securitiesdebt with similar characteristics offered by corporations with credit ratings similar to those of FirstEnergy, FES, the Utilities and the Utilities.other subsidiaries.
(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.

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FES and the Utilities periodically evaluate their investments for other-than-temporary impairment. They first consider their intent and ability to hold an equity investment until recovery and then consider, among other factors, the duration and the extent to which the security’s fair value has been less than cost and the near-term financial prospects of the security issuer when evaluating an investment for impairment. For debt securities, FES and the Utilities consider their intent to hold the security, the likelihood that they will be required to sell the security before recovery of their cost basis, and the likelihood of recovery of the security’s entire amortized cost basis.
Available-For-Sale Securities
FES and the Utilities hold debt and equity securities within their nuclear decommissioning trusts, nuclear fuel disposal trusts and NUG trusts. These trust investments are considered as available-for-sale at fair market value. FES and the Utilities have no securities held for trading purposes.
The following table summarizes the amortized cost basis, unrealized gains and losses and fair values of investments held in nuclear decommissioning trusts, nuclear fuel disposal trusts and NUG trusts as of September 30, 2010March 31, 2011 and December 31, 2009:2010:
                                                                
 September 30, 2010(1) December 31, 2009(2)  March 31, 2011(1) December 31, 2010(2) 
 Cost Unrealized Unrealized Fair Cost Unrealized Unrealized Fair  Cost Unrealized Unrealized Fair Cost Unrealized Unrealized Fair 
 Basis Gains Losses Value Basis Gains Losses Value  Basis Gains Losses Value Basis Gains Losses Value 
 (In millions)  (In millions) 
Debt securities
  
FirstEnergy $1,795 $73 $— $1,868 $1,727 $22 $— $1,749  $1,985 $32 $— $2,017 $1,699 $31 $— $1,730 
FES 1,079 39 — 1,118 1,043 3 — 1,046  1,012 18 — 1,030 980 13 — 993 
OE 124 4 — 128 55 — — 55  124 1 — 125 123 1 — 124 
TE 31 1 — 32 72 — — 72  51 — — 51 42 — — 42 
JCP&L 277 15 — 292 271 9 — 280  358 7 — 365 281 9 — 290 
Met-Ed 129 8 — 137 120 5 — 125  240 4 — 244 127 4 — 131 
Penelec 155 6 — 161 166 5 — 171  200 2 — 202 145 4 — 149 
  
Equity securities
  
FirstEnergy $261 $44 $— $305 $252 $43 $— $295  $186 $7 $— $193 $268 $69 $— $337 
FES 88 5 — 93 — — — — 
TE 24 1 — 25 — — — — 
JCP&L 78 9 — 87 74 11 — 85  21 — — 21 80 17 — 97 
Met-Ed 122 23 — 145 117 23 — 140  33 1 — 34 125 35 — 160 
Penelec 62 10 — 72 61 9 — 70  20 — — 20 63 16 — 79 
(1) Excludes cash balances:investments, receivables, payables, deferred taxes and accrued income: FirstEnergy — $93$97 million; FES — $40$37 million; OE — $2 million; TE — $44$1 million; JCP&L — $5$12 million; Met-Ed — $(5)$27 million and Penelec — $6$18 million.
 
(2) Excludes cash balances:investments, receivables, payables, deferred taxes and accrued income: FirstEnergy — $137$193 million; FES — $43$153 million; OE — $66$3 million; TE — $2$34 million; JCP&L — $3 million; Met-Ed — $(3) million and Penelec — $23$4 million.

 

2831

Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales net of adjustments recorded, and interest and dividend income for the nine-month periodthree months ended September 30,March 31, 2011 and 2010 and 2009 were as follows:
                             
September 30, 2010 FirstEnergy  FES  OE  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
Proceeds from sales $2,577  $1,478  $79  $118  $340  $420  $141 
Realized gains  132   101   2   3   10   10   6 
Realized losses  118   88   —   1   10   12   7 
Interest and dividend income  56   33   2   1   10   5   5 
                 
              Interest and 
March 31, 2011 Sales Proceeds  Realized Gains  Realized Losses  Dividend Income 
  (In millions) 
FirstEnergy $970  $100  $(29) $24 
FES  216   12   (15)  15 
OE  8   —   —   1 
TE  14   1   (1)  1 
JCP&L  217   22   (4)  4 
Met-Ed  336   43   (5)  2 
Penelec  179   22   (4)  1 
                             
September 30, 2009 FirstEnergy  FES  OE  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
Proceeds from sales $3,040  $2,153  $207  $171  $339  $89  $81 
Realized gains  186   162   11   7��  4   1   1 
Realized losses  96   62   3   —   11   13   7 
Interest and dividend income  47   22   4   2   10   5   4 
                 
              Interest and 
March 31, 2010 Sales Proceeds  Realized Gains  Realized Losses  Dividend Income 
  (In millions) 
FirstEnergy $733  $37  $(51) $22 
FES  272   13   (24)  13 
OE  2   —   —   1 
TE  31   1   (1)  1 
JCP&L  190   8   (8)  4 
Met-Ed  144   9   (11)  2 
Penelec  93   6   (7)  1 
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. 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 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 plans’ 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.
FirstEnergy recognized $3 million and $11 million of net realized losses for the three-month period ended March 31, 2011 and 2010, respectively, 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 as of September 30, 2010March 31, 2011 and December 31, 2009:2010:
                                                                
 September 30, 2010 December 31, 2009  March 31, 2011 December 31, 2010 
 Cost Unrealized Unrealized Fair Cost Unrealized Unrealized Fair  Cost Unrealized Unrealized Fair Cost Unrealized Unrealized Fair 
 Basis Gains Losses Value Basis Gains Losses Value  Basis Gains Losses Value Basis Gains Losses Value 
 (In millions)  (In millions) 
Debt Securities
  
FirstEnergy $486 $99 $— $585 $544 $72 $— $616  $422 $79 $— $501 $476 $91 $— $567 
OE 205 60 — 265 217 29 — 246  190 45 — 235 190 51 — 241 
CEI 340 31 — 371 389 43 — 432  287 33 — 320 340 41 — 381 
Investments in emission allowances, employee benefits and cost and equity method investments totaling $256$345 million as of September 30, 2010,March 31, 2011 and $264$259 million as of December 31, 20092010 are not required to be disclosed and are therefore excluded from the amounts reported above.

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Notes Receivable
The table below provides the approximate fair value and related carrying amounts of notes receivable as of September 30, 2010March 31, 2011 and December 31, 2009.2010. 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 range from 2013 to 2021.
                 
  September 30, 2010  December 31, 2009 
  Carrying  Fair  Carrying  Fair 
  Value  Value  Value  Value 
  (In millions) 
Notes Receivable
                
FirstEnergy $7  $8  $36  $35 
FES  —   —   2   1 
TE  104   114   124   141 
The fair value of notes receivable represents the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms.
                 
  March 31, 2011  December 31, 2010 
  Carrying  Fair  Carrying  Fair 
  Value  Value  Value  Value 
  (In millions) 
Notes Receivable
                
FirstEnergy $7  $8  $7  $8 
TE  82   94   104   118 
(C) RECURRING FAIR VALUE MEASUREMENTS
Fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between willing market participants on the measurement date. A fair value hierarchy has been established that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy 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 wherein which 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.

29

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 may 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 determination of the fair value measures takes into consideration various factors. These factors include nonperformance risk, including counterparty credit risk and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of nonperformance risk was immaterial in the fair value measurements.
The following tables set forth financial assets and financial liabilities that are accounted for at fair value by level within the fair value hierarchy as of September 30, 2010March 31, 2011 and December 31, 2009.2010. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. FirstEnergy’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the fair valuation of assets and liabilities and their placement within the fair value hierarchy levels.
                             
  Recurring Fair Value Measures as of September 30, 2010 
  Level 1 
  FirstEnergy  FES  OE  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
Assets
                            
Nuclear Decommissioning Trust Investments — equity securities(1)
 $305  $—  $—  $—  $88  $145  $73 
                      
Total Assets(2)
 $305  $—  $—  $—  $88  $145  $73 
                      
                             
Liabilities
                            
Derivatives — commodity contracts $2  $2  $—  $—  $—  $—  $— 
                      
Total Liabilities
 $2  $2  $—  $—  $—  $—  $— 
                      
 The fair value of financial assets and liabilities as of March 31, 2011 assumed in the merger with Allegheny totaled $52 million and $51 million, respectively. There were no significant transfers between Level 1, Level 2 and Level 3 as of March 31, 2011 and December 31, 2010.

 

3033

                             
  Level 2 
  FirstEnergy  FES  OE  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
Assets
                            
Nuclear Decommissioning Trust Investments
                            
U.S. government debt securities $619  $337  $127  $26  $37  $82  $10 
U.S. state debt securities  88   —   —   —   29   —   59 
Foreign government debt securities  285   285   —   —   —   —   — 
Corporate debt securities  580   496   —   6   23   47   8 
Other  101   38   6   45   2   9   1 
                      
Total Nuclear Decommissioning Trust Investments
 $1,673  $1,156  $133  $77  $91  $138  $78 
                      
                             
Rabbi Trust Investments
                            
Equity securities — financial $1  $—  $—  $—  $—  $—  $— 
Other  11   —   —   —   —   —   — 
                      
Total Rabbi Trust Investments
 $12  $—  $—  $—  $—  $—  $— 
                      
                             
Nuclear Fuel Disposal Trust Investments
                            
U.S. state debt securities $209  $—  $—  $—  $209  $—  $— 
                      
Total Nuclear Fuel Disposal Trust Investments
 $209  $—  $—  $—  $209  $—  $— 
                      
                             
NUG Trust Investments
                            
U.S. state debt securities $86  $—  $—  $—  $—  $—  $86 
Other  6   —   —   —   —   —   6 
                      
Total NUG Trust Investments
 $92  $—  $—  $—  $—  $—  $92 
                      
                             
Derivatives
                            
Commodity contracts $183  $174  $—  $—  $2  $5  $2 
                      
Total Derivatives Contracts
 $183  $174  $—  $—  $2  $5  $2 
                      
Total Assets(2)
 $2,169  $1,330  $133  $77  $302  $143  $172 
                      
                             
Liabilities
                            
Derivatives
                            
Commodity contracts $329  $329  $—  $—  $—  $—  $— 
                      
Total Liabilities
 $329  $329  $—  $—  $—  $—  $— 
                      
FirstEnergy Corp.
                             
  Level 3 
  FirstEnergy  FES  OE  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
Assets
                            
Derivatives — NUG contracts(3)
 $116  $—  $—  $—  $7  $104  $6 
                      
                             
Liabilities
                            
Derivatives — NUG contracts(3)
 $756  $—  $—  $—  $386  $175  $194 
                      
The following tables summarize assets and liabilities recorded on FirstEnergy’s Consolidated Balance Sheets at fair value as of March��31, 2011 and December 31, 2010:
                 
March 31, 2011 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
Corporate debt securities $—  $877  $—  $877 
Derivative assets — commodity contracts  —   524   —   524 
Derivative assets — FTRs  —   —   1   1 
Derivative assets — interest rate swaps  —   4   —   4 
Derivative assets — NUG contracts(1)
  —   —   117   117 
Equity securities(2)
  194   —   —   194 
Foreign government debt securities  —   150   —   150 
U.S. government debt securities  —   681   —   681 
U.S. state debt securities  —   297   —   297 
             
Other(4)
  —   148   —   148 
             
Total assets
 $194  $2,681  $118  $2,993 
             
                 
Liabilities
                
Derivative liabilities — commodity contracts $—  $(583) $—  $(583)
Derivative liabilities — FTRs  —   —   (12)  (12)
Derivative liabilities — interest rate swaps  —   (5)  —   (5)
             
Derivative liabilities — NUG contracts(1)
  —   —   (478)  (478)
             
Total liabilities
 $—  $(588) $(490) $(1,078)
             
                 
Net assets (liabilities)(3)
 $194  $2,093  $(372) $1,915 
             
                 
December 31, 2010 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
Corporate debt securities $—  $597  $—  $597 
Derivative assets — commodity contracts  —   250   —   250 
Derivative assets — NUG contracts(1)
  —   —   122   122 
Equity securities(2)
  338   —   —   338 
Foreign government debt securities  —   149   —   149 
U.S. government debt securities  —   595   —   595 
U.S. state debt securities  —   379   —   379 
Other(4)
  —   219   —   219 
             
Total assets
 $338  $2,189  $122  $2,649 
             
                 
Liabilities
                
Derivative liabilities — commodity contracts $—  $(348) $—  $(348)
Derivative liabilities — NUG contracts(1)
  —   —   (466)  (466)
             
Total liabilities
 $—  $(348) $(466) $(814)
    ��        
                 
Net assets (liabilities)(3)
 $338  $1,841  $(344) $1,835 
             
(1) NUG contracts are subject to regulatory accounting and do not impact earnings.
(2)NDT funds hold equity portfolios whosethe performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.
 
(2)(3) Excludes $(13)$(31) million and $(7) million as of March 31, 2011 and December 31, 2010, respectively, of receivables, payables, deferred taxes and accrued income.income associated with the financial instruments reflected within the fair value table.
(4)Primarily consists of cash and cash equivalents.

34

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 periods ending March 31, 2011 and December 31, 2010, respectively:
             
  Derivative Asset(1)  Derivative Liability(1)               Net(1)               
  (In millions) 
January 1, 2011 Balance $122  $(466) $(344)
Realized gain (loss)  —   —   — 
Unrealized gain (loss)  (1)  (89)  (90)
Purchases  —   —   — 
Issuances  —   —   — 
Sales  —   —   — 
Settlements  (3)  77   74 
Transfers in (out) of Level 3  —   (12)  (12)
          
March 31, 2011 Balance $118  $(490) $(372)
          
             
January 1, 2010 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)
          
(1)Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings.
FirstEnergy Solutions Corp.
The following tables summarize assets and liabilities recorded on FES’ Consolidated Balance Sheets at fair value as of March 31, 2011 and December 31, 2010:
                 
March 31, 2011 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
Corporate debt securities $—  $567  $—  $567 
Derivative assets — commodity contracts  —   476   —   476 
Derivative assets — FTRs  —   —   1   1 
Equity securities(3)
  93   —   —   93 
Foreign government debt securities  —   148   —   148 
U.S. government debt securities  —   304   —   304 
             
U.S. state debt securities  —   8   —   8 
Other(2)
  —   43   —   43 
             
Total assets
 $93  $1,546  $1  $1,640 
             
                 
Liabilities
                
Derivative liabilities — commodity contracts $—  $(549) $—  $(549)
             
Total liabilities
 $—  $(549) $—  $(549)
             
                 
Net assets (liabilities)(1)
 $93  $997  $1  $1,091 
             

35

                 
December 31, 2010 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
Corporate debt securities $—  $528  $—  $528 
Derivative assets — commodity contracts  —   241   —   241 
Foreign government debt securities  —   147   —   147 
U.S. government debt securities  —   308   —   308 
U.S. state debt securities  —   6   —   6 
Other(2)
  —   148   —   148 
             
Total assets
 $—  $1,378  $—  $1,378 
             
                 
Liabilities
                
Derivative liabilities – commodity contracts $—  $(348) $—  $(348)
             
Total liabilities
 $—  $(348) $—  $(348)
             
                 
Net assets (liabilities)(1)
 $—  $1,030  $—  $1,030 
             
(1)Excludes $(3) million and $7 million as of March 31, 2011 and December 31, 2010, respectively, of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table.
(2)Primarily consists of cash and cash equivalents.
 
(3)NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.
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 period ending March 31, 2011:
             
  Derivative Asset  Derivative Liability  Net 
  FTRs  FTRs             FTRs            
  (In millions) 
January 1, 2011 Balance $—  $—  $— 
Realized gain (loss)  —   —   — 
Unrealized gain (loss)  1   —   1 
Purchases  —   —   — 
Issuances  —   —   — 
Sales  —   —   — 
Settlements  —   —   — 
Transfers in (out) of Level 3  —   —   — 
          
March 31, 2011 Balance $1  $—  $1 
          
Ohio Edison Company
The following tables summarize assets and liabilities recorded on OE’s Consolidated Balance Sheets at fair value as of March 31, 2011 and December 31, 2010:
                 
March 31, 2011 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
U.S. government debt securities $—  $125  $—  $125 
Other  —   6   —   6 
             
Total assets(1)
 $—  $131  $—  $131 
             
                 
December 31, 2010 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
U.S. government debt securities $—  $124  $—  $124 
Other  —   2   —   2 
             
Total assets(1)
 $—  $126  $—  $126 
             
(1)Excludes $(3) million and $1 million as of March 31, 2011 and December 31, 2010 of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table.

36

Toledo Edison Company
The following tables summarize assets and liabilities recorded on TE’s Consolidated Balance Sheets at fair value as of March 31, 2011 and December 31, 2010:
                 
March 31, 2011 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
Corporate debt securities $—  $16  $—  $16 
Equity securities(3)
  25   —   —   25 
U.S. government debt securities  —   32   —   32 
U.S. state debt securities  —   2   —   2 
Other(2)
  —   3   —   3 
             
Total assets(1)
 $25  $53  $—  $78 
             
                 
December 31, 2010 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
Corporate debt securities $—  $7  $—  $7 
U.S. government debt securities  —   33   —   33 
U.S. state debt securities  —   1   —   1 
Other(2)
  —   35   —   35 
             
Total assets(1)
 $—  $76  $—  $76 
             
(1)Excludes $(1) million and $2 million as of March 31, 2011 and December 31, 2010 of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table.
(2)Primarily consists of cash and cash equivalents.
(3)NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.
Jersey Central Power & Light Company
The following tables summarize assets and liabilities recorded on JCP&L’s Consolidated Balance Sheets at fair value as of March 31, 2011 and December 31, 2010:
                 
March 31, 2011 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
Corporate debt securities $—  $92  $—  $92 
Derivative assets — commodity contracts  —   —   —   — 
Derivative assets — NUG contracts(1)
  —   —   6   6 
Equity securities(2)
  21   —   —   21 
Foreign government debt securities  —   1   —   1 
U.S. government debt securities  —   60   —   60 
U.S. state debt securities  —   214   —   214 
             
Other  —   16   —   16 
             
Total assets
 $21  $383  $6  $410 
             
                 
Liabilities
                
Derivative liabilities – NUG contracts(1)
 $—  $—  $(239) $(239)
             
Total liabilities
 $—  $—  $(239) $(239)
             
                 
Net assets (liabilities)(3)
 $21  $383  $(233) $171 
             

37

                 
December 31, 2010 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
Corporate debt securities $—  $23  $—  $23 
Derivative assets — commodity contracts  —   2   —   2 
Derivative assets — NUG contracts(1)
  —   —   6   6 
Equity securities(2)
  96   —   —   96 
U.S. government debt securities  —   33   —   33 
U.S. state debt securities  —   236   —   236 
Other  —   4   —   4 
             
Total assets
 $96  $298  $6  $400 
             
                 
Liabilities
                
Derivative liabilities – NUG contracts(1)
 $—  $—  $(233) $(233)
             
Total liabilities
 $—  $—  $(233) $(233)
             
                 
Net assets (liabilities)(3)
 $96  $298  $(227) $167 
             
(1) NUG contracts are subject to regulatory accounting and do not impact earnings.
                             
  Recurring Fair Value Measures as of December 31, 2009 
  Level 1 
  FirstEnergy  FES  OE  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
Assets
                            
Nuclear Decommissioning Trust Investments — equity securities(1)
 $294  $—  $—  $—  $87  $133  $74 
                      
Total Assets(2)
 $294  $—  $—  $—  $87  $133  $74 
                      
                             
Liabilities
                            
Derivatives — commodity contracts $11  $11  $—  $—  $—  $—  $— 
                      
Total Liabilities
 $11  $11  $—  $—  $—  $—  $— 
                      

31

                             
  Level 2 
  FirstEnergy  FES  OE  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
Assets
                            
Nuclear Decommissioning Trust Investments
                            
U.S. government debt securities $558  $306  $118  $72  $23  $30  $9 
U.S. state debt securities  188   15   —   —   41   82   50 
Foreign government debt securities  279   279   —   —   —   —   — 
Corporate debt securities  484   443   —   —   15   20   6 
Other  35   29   2   —   1   2   1 
                      
Total Nuclear Decommissioning Trust Investments
 $1,544  $1,072  $120  $72  $80  $134  $66 
                      
                             
Rabbi Trust Investments
                            
Equity securities — financial $1  $—  $—  $—  $—  $—  $— 
Other  9   —   —   —   —   —   — 
                      
Total Rabbi Trust Investments
 $10  $—  $—  $—  $—  $—  $— 
                      
                             
Nuclear Fuel Disposal Trust Investments
                            
U.S. state debt securities $189  $—  $—  $—  $189  $—  $— 
Other  11   —   —   —   11   —   — 
                      
Total Nuclear Fuel Disposal Trust Investments
 $200  $—  $—  $—  $200  $—  $— 
                      
                             
NUG Trust Investments
                            
U.S. state debt securities $101  $—  $—  $—  $—  $—  $101 
Other  19   —   —   —   —   —   19 
                      
Total NUG Trust Investments
 $120  $—  $—  $—  $—  $—  $120 
                      
                             
Derivatives — Commodity Contracts
 $34  $15  $—  $—  $5  $9  $5 
                             
Other
 $1  $—  $—  $—  $—  $—  $— 
                      
Total Assets(2)
 $1,909  $1,087  $120  $72  $285  $143  $191 
                      
                             
Liabilities
                            
Derivatives — commodity contracts $224  $224  $—  $—  $—  $—  $— 
                      
Total Liabilities
 $224  $224  $—  $—  $—  $—  $— 
                      
                             
  Level 3 
  FirstEnergy  FES  OE  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
Assets
                            
Derivatives — NUG contracts(3)
 $200  $—  $—  $—  $9  $176  $15 
                      
                             
Liabilities
                            
Derivatives — NUG contracts(3)
 $643  $—  $—  $—  $399  $143  $101 
                      
(1)(2) NDT funds hold equity portfolios whosethe performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.
 
(2)(3) Excludes $21$(8) million and $(3) million as of March 31, 2011 and December 31, 2010 of receivables, payables, deferred taxes and accrued income.
(3)NUG contracts are subject to regulatory accounting and do not impact earnings.income associated with the financial instruments reflected within the fair value table.
The determinationRollforward of the above fair value measures takes into consideration various factors. These factors include nonperformance risk, including counterparty credit risk and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of nonperformance risk was immaterial in the fair value measurements.Level 3 Measurements

32

The following tables set forthtable 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 threeperiods ending March 31, 2011 and nine months ended September 30, 2010 and 2009 (in millions):December 31, 2010:
                 
  FirstEnergy  JCP&L  Met-Ed  Penelec 
Balance as of January 1, 2010 $(444) $(391) $33  $(86)
Settlements(1)
  209   99   60   50 
Unrealized losses(1)
  (405)  (88)  (164)  (153)
             
Balance as of September 30, 2010 $(640) $(380) $(71) $(189)
             
                 
Balance as of July 1, 2010 $(557) $(371) $(38) $(148)
Settlements(1)
  63   29   23   11 
Unrealized losses(1)
  (146)  (38)  (56)  (52)
             
Balance as of September 30, 2010 $(640) $(380) $(71) $(189)
             
                 
  FirstEnergy  JCP&L  Met-Ed  Penelec 
Balance as of January 1, 2009 $(332) $(518) $150  $36 
Settlements(1)
  273   132   63   78 
Unrealized losses(1)
  (406)  (30)  (178)  (198)
             
Balance as of September 30, 2009 $(465) $(416) $35  $(84)
             
                 
Balance as of July 1, 2009 $(536) $(466) $23  $(93)
Settlements(1)
  93   42   20   31 
Unrealized gains (losses)(1)
  (22)  8   (8)  (22)
             
Balance as of September 30, 2009 $(465) $(416) $35  $(84)
             
             
  Derivative Asset  Derivative Liability  Net 
  NUG Contracts(1)  NUG Contracts(1)  NUG Contracts(1) 
  (In millions) 
January 1, 2011 Balance $6  $(233) $(227)
Realized gain (loss)  —   —   — 
Unrealized gain (loss)  —   (42)  (42)
Purchases  —   —   — 
Issuances  —   —   — 
Sales  —   —   — 
Settlements  —   36   36 
Transfers in (out) of Level 3  —   —   — 
          
March 31, 2011 Balance $6  $(239) $(233)
          
             
January 1, 2010 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)
          
(1) Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings.

38

Metropolitan Edison Company
The following tables summarize assets and liabilities recorded on Met-Ed’s Consolidated Balance Sheets at fair value as of March 31, 2011 and December 31, 2010:
                 
March 31, 2011 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
Corporate debt securities $—  $131  $—  $131 
Derivative assets — commodity contracts  —   —   —   — 
Derivative assets — NUG contracts(1)
  —   —   107   107 
Equity securities(2)
  34   —   —   34 
Foreign government debt securities  —   2   —   2 
U.S. government debt securities  —   100   —   100 
U.S. state debt securities  —   2   —   2 
Other  —   37   —   37 
             
Total assets
 $34  $272  $107  $413 
             
                 
Liabilities
                
Derivative liabilities – NUG contracts(1)
 $—  $—  $(118) $(118)
             
Total liabilities
 $—  $—  $(118) $(118)
             
                 
Net assets (liabilities)(3)
 $34  $272  $(11) $295 
             
                 
December 31, 2010 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
Corporate debt securities $—  $32  $—  $32 
Derivative assets — commodity contracts  —   5   —   5 
Derivative assets — NUG contracts(1)
  —   —   112   112 
Equity securities(2)
  160   —   —   160 
Foreign government debt securities  —   1   —   1 
U.S. government debt securities  —   88   —   88 
U.S. state debt securities  —   2   —   2 
Other  —   14   —   14 
             
Total assets
 $160  $142  $112  $414 
             
                 
Liabilities
                
Derivative liabilities – NUG contracts(1)
 $—  $—  $(116) $(116)
             
Total liabilities
 $—  $—  $(116) $(116)
             
                 
Net assets (liabilities)(3)
 $160  $142  $(4) $298 
             
(1)NUG contracts are subject to regulatory accounting and do not impact earnings.
(2)NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.
(3)Excludes $(1) million and $(9) million as of March 31, 2011 and December 31, 2010, respectively, of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table.

39

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 periods ending March 31, 2011 and December 31, 2010:
             
  Derivative Asset  Derivative Liability  Net 
  NUG Contracts(1)  NUG Contracts(1)  NUG Contracts(1) 
  (In millions) 
January 1, 2011 Balance $112  $(116) $(4)
Realized gain (loss)  —   —   — 
Unrealized gain (loss)  (2)  (16)  (18)
Purchases  —   —   — 
Issuances  —   —   — 
Sales  —   —   — 
Settlements  (3)  14   11 
Transfers in (out) of Level 3  —   —   — 
          
March 31, 2011 Balance $107  $(118) $(11)
          
             
January 1, 2010 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)
          
(1)Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings.
Pennsylvania Electric Company
The following tables summarize assets and liabilities recorded on Penelec’s Consolidated Balance Sheets at fair value as of March 31, 2011 and December 31, 2010:
                 
March 31, 2011 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
Corporate debt securities $—  $70  $—  $70 
Derivative assets — commodity contracts  —   —   —   — 
Derivative assets — NUG contracts(1)
  —   —   4   4 
Equity securities(2)
  20   —   —   20 
Foreign government debt securities  —   —   —   — 
U.S. government debt securities  —   60   —   60 
U.S. state debt securities  —   72   —   72 
             
Other  —   32   —   32 
             
Total assets
 $20  $234  $4  $258 
             
                 
Liabilities
                
Derivative liabilities – NUG contracts(1)
 $—  $—  $(122) $(122)
             
Total liabilities
 $—  $—  $(122) $(122)
             
                 
Net assets (liabilities)(3)
 $20  $234  $(118) $136 
             

40

                 
December 31, 2010 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
Corporate debt securities $—  $8  $—  $8 
Derivative assets — commodity contracts  —   2   —   2 
Derivative assets — NUG contracts(1)
  —   —   4   4 
Equity securities(2)
  81   —   —   81 
U.S. government debt securities  —   9   —   9 
U.S. state debt securities  —   133   —   133 
Other  —   5   —   5 
             
Total assets
 $81  $157  $4  $242 
             
                 
Liabilities
                
Derivative liabilities – NUG contracts(1)
 $—  $—  $(117) $(117)
             
Total liabilities
 $—  $—  $(117) $(117)
             
                 
Net assets (liabilities)(3)
 $81  $157  $(113) $125 
             
(1)NUG contracts are subject to regulatory accounting and do not impact earnings.
(2)NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.
(3)Excludes $(15) million and $(3) million as of March 31, 2011 and December 31, 2010, respectively, of receivables, payables 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 and commodity contracts held by Penelec and classified as Level 3 in the fair value hierarchy for the periods ended March 31, 2011 and December 31, 2010:
             
  Derivative Asset  Derivative Liability  Net 
  NUG Contracts(1)  NUG Contracts(1)  NUG Contracts(1) 
  (In millions) 
January 1, 2011 Balance $4  $(117) $(113)
Realized gain (loss)  —   —   — 
Unrealized gain (loss)  —   (30)  (30)
Purchases  —   —   — 
Issuances  —   —   — 
Sales  —   —   — 
Settlements  —   25   25 
Transfers in (out) of Level 3  —   —   — 
          
March 31, 2011 Balance $4  $(122) $(118)
          
             
January 1, 2010 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)
          
(1)Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings.

41

5. DERIVATIVE INSTRUMENTS
FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. To manage the volatility relating to these exposures, FirstEnergy usesestablished a variety of derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used for risk management purposes. In addition to derivatives, FirstEnergy also enters into master netting agreements with certain third parties. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, which provides general management oversight for risk management activities throughout FirstEnergy. The Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practices.practice. FirstEnergy also uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps. In addition to derivatives, FirstEnergy also enters into master netting agreements with certain third parties.
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 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 meetqualify and are designated as cash flow hedge instruments are recorded to AOCL. Change in the normal purchases 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. Based on derivative contracts heldinstruments that are not designated as of September 30, 2010, an adverse 10% change in commodity prices would decrease net income by approximately $6 million ($4 million net of tax) during the next twelve months. A hypothetical 10% increasecash flow hedge instruments are recorded in the interest rates associated with variable-rate debt would decrease net income by approximately $1 million for the three and nine months ended September 30, 2010.statement on a mark-to-market basis. FirstEnergy’s 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 the derivative contract are reported as a component of AOCL 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 losses included in AOCL associated with dedesignated cash flow hedges totaled $6 million as of March 31, 2011. Since the forecasted transactions remain probable of occurring, these amounts were “frozen” in AOCL and will be amortized into earnings over the life of the hedging instruments. Reclassifications from AOCL into other operating expense totaled $5 million for the three-months ended March 31, 2011. Approximately $16 million will be amortized to earnings as expense 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 September 30, 2010,March 31, 2011, no forward starting swap agreements were outstanding.
Total unamortized losses included in AOCL associated with prior interest rate cash flow hedges totaled $95$87 million ($6257 million net of tax) as of September 30, 2010.March 31, 2011. Based on current estimates, approximately $11$10 million will be amortized to interest expense during the next twelve months. The table below providesReclassifications from AOCL into interest expense totaled $3 million for the activity of AOCL related to interest rate cash flow hedges as of September 30, 2010three-months ended March 31, 2011 and 2009.2010.
                 
  Three Months Ended  Nine Months Ended 
  September 30  September 30 
  2010  2009  2010  2009 
  (In millions)  (In millions) 
Effective Portion                
Gain (Loss) Recognized in AOCL $—  $(17) $—  $(18)
Reclassification from AOCL into Interest Expense  (3)  (26)  (9)  (37)

33

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 portfolio of its subsidiaries. These derivativesderivative 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 September 30, 2010,March 31, 2011, no fixed-for-floating interest rate swap agreements were outstanding.
As of March 31, 2010, FirstEnergy held fixed-for-floating interest rate swap agreements with combined notional amounts of $950 million. The gains included in interest expense related to interest rate swaps totaled $1 million and the fair value of the derivative instruments totaled $(3) million. There was no impact on the results of operations as a result of ineffectiveness from fair value hedges.
Total unamortized gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements totaled $129$118 million ($8477 million net of tax) as of September 30, 2010.March 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 $5 million and $7$1 million for the threethree-months ended March 31, 2011 and nine months ended September 30, 2010.2010, 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.

42

The following tables summarize the fair value of commodity derivatives in FirstEnergy’s Consolidated Balance Sheets:
                   
Cash Flow Hedges 
Derivative Assets  Derivative Liabilities 
  Fair Value    Fair Value 
  September 30,  December 31,    September 30,  December 31, 
  2010  2009    2010  2009 
  (In millions)    (In millions) 
    
Electricity Forwards         Electricity Forwards        
Current Assets $77  $3  Current Liabilities $87  $7 
NonCurrent Assets  73   11  NonCurrent Liabilities  70   12 
Natural Gas Futures         Natural Gas Futures        
Current Assets  —   —  Current Liabilities  1   9 
NonCurrent Assets  —   —  NonCurrent Liabilities  —   — 
Other         Other        
Current Assets  —   —  Current Liabilities  —   2 
NonCurrent Assets  —   —  NonCurrent Liabilities  —   — 
               
  $150  $14    $158  $30 
               
                   
Economic Hedges 
Derivative Assets  Derivative Liabilities 
  Fair Value    Fair Value 
  September 30,  December 31,    September 30,  December 31, 
  2010  2009    2010  2009 
  (In millions)    (In millions) 
                   
NUG Contracts         NUG Contracts        
Power Purchase         Power Purchase        
Contract Asset $116  $200  Contract Liability $756  $643 
Other         Other        
Current Assets  17   —  Current Liabilities  138   106 
NonCurrent Assets  15   19  NonCurrent Liabilities  34   97 
               
   148   219     928   846 
               
Total Commodity Derivatives $298  $233  Total Commodity Derivatives $1,086  $876 
               
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, primarily natural gas 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. Interest rate swaps include two interest rate swap agreements that expire during 2011 with an aggregate notional value of $200 million that were entered into during 2003 to substantially offset two existing interest rate swaps with the same counterparty. The 2003 agreements effectively locked in a net liability and substantially eliminated future income volatility from the interest rate swap positions but do not qualify for cash flow hedge accounting. Derivative instruments are not used in quantities greater than forecasted needs.
As of March 31, 2011, FirstEnergy’s net liability position under commodity derivative contracts was $59 million, which primarily related to FES positions. Under these commodity derivative contracts, FES posted $120 million and Allegheny posted $1 million in collateral. Certain commodity derivative contracts include credit risk related contingent features that would require FES to post $24 million of additional collateral if the credit rating for its debt were to fall below investment grade.
Based on derivative contracts held as of March 31, 2011, an adverse 10% change in commodity prices would decrease net income by approximately $12 million ($7 million net of tax) 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. These future obligations are reflected on the Consolidated Balance Sheets; and have not been designated as cash flow hedge instruments. FirstEnergy acquires the majority of its FTRs in an annual auction through a self-scheduling process involving the use of auction revenue rights allocated to members of an RTO that have load serving obligations. FirstEnergy initially records FTRs at the FTR 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 accounting period prior to settlement. Changes in the fair value of FTRs held by FirstEnergy’s unregulated subsidiaries are 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.
The following tables summarize the fair value of derivative instruments in FirstEnergy’s Consolidated Balance Sheets:
Derivatives not designated as hedging instruments as of March 31, 2011:
         
Derivative Assets 
  Fair Value 
  March 31,  December 31, 
  2011  2010 
  (In millions) 
         
Power Contracts        
Current Assets $332  $151 
Noncurrent Assets  192   89 
FTRs        
Current Assets  1   — 
Noncurrent Assets  —   — 
NUGs        
Current Assets  3   3 
Noncurrent Assets  114   119 
Interest Rate Swaps        
Current Assets  4   — 
Noncurrent Assets  —   — 
Other        
Current Assets  —   10 
Noncurrent Assets  —   — 
       
Total Derivatives $646  $372 
       
         
Derivative Liabilities 
  Fair Value 
  March 31,  December 31, 
  2011  2010 
  (In millions) 
         
Power Contracts        
Current Liabilities $408  $266 
Noncurrent Liabilities  175   81 
FTRs        
Current Liabilities  12   — 
Noncurrent Liabilities  —   — 
NUGs        
Current Liabilities  277   229 
Noncurrent Liabilities  202   238 
Interest Rate Swaps        
Current Liabilities  5   — 
Noncurrent Liabilities  —   — 
Other        
Current Liabilities  —   — 
Noncurrent Liabilities  —   — 
       
Total Derivatives $1,079  $814 
       

43

The following table summarizes the volume of FirstEnergy’s outstanding derivative transactions as of September 30, 2010:March 31, 2011:
                 
  Purchases  Sales  Net  Units 
  (In thousands) 
Electricity Forwards  28,456   (32,604)  (4,148) MWH
Heating Oil Futures  840   —   840  Gallons
Natural Gas Futures  500   (500)  —  mmBtu
                 
  Purchases  Sales  Net  Units
  (In thousands) 
Power Contracts  83,603   (100,407)  (16,804) MWH
FTRs  18,199   (130)  18,069  MWH
Interest Rate Swaps  200,000   (200,000)  —  notional dollars
NUGs  29,824   —   29,824  MWH

34

The effect of derivative instruments on the consolidated statements of income and comprehensive income for the three and nine months ended September 30,March 31, 2011 and 2010, and 2009, are summarized in the following tables:
                           
 Three Months Ended September 30,  Three Months Ended March 31, 
 Electricity Natural Gas Heating Oil    Power Interest     
Derivatives in Cash Flow Hedging Relationships Forwards Futures Futures Total 
 Contracts FTRs Rate Swaps Other Total 
 (In millions) 
Derivatives in a Hedging Relationship
 
2011
 
Gain (Loss) Recognized in AOCL (Effective Portion) $(9) $— $— — $(9)
Effective Gain (Loss) Reclassified to:(1)
 
Purchase Power Expense 14 — — — 14 
Wholesale Revenue  (3) — — —  (3)
 (In millions)  
2010
  
Gain (Loss) Recognized in AOCL (Effective Portion) $(2) $— $— $(2) $(2) — — 3 $1 
Effective Gain (Loss) Reclassified to:(1)
  
Purchased Power Expense  (1) — —  (1)
Purchase Power Expense 2 — — — 2 
Fuel Expense —  (3)  (1)  (4) — — — 4 4 
  
2009
 
Gain (Loss) Recognized in AOCL (Effective Portion) $15 $(2) $— $13 
Effective Gain (Loss) Reclassified to:(1)
 
Purchased Power Expense 11 — — 11 
Fuel Expense —  (4)  (2)  (6)
Derivatives Not in a Hedging Relationship
 
2011
 
Unrealized Gain (Loss) Recognized in: 
Purchase Power Expense $29 — — — $29 
Wholesale Revenue — — — — — 
Other Operating Expense  (20) 1 — —  (19)
Realized Gain (Loss) Reclassified to: 
Purchase Power Expense  (19)  (2) — —  (21)
Wholesale Revenue  (2) —  (1) —  (3)
 
2010
 
Unrealized Gain (Loss) Recognized in: 
Purchase Power Expense $(27) — — — $(27)
Realized Gain (Loss) Reclassified to: 
Purchase Power Expense  (25) — — —  (25)

44

                 
  Nine Months Ended September 30, 
  Electricity  Natural Gas  Heating Oil    
Derivatives in Cash Flow Hedging Relationships Forwards  Futures  Futures  Total 
  (In millions) 
2010
                
Gain (Loss) Recognized in AOCL (Effective Portion) $(15) $(1) $—  $(16)
Effective Gain (Loss) Reclassified to:(1)
                
Purchased Power Expense  (12)  —   —   (12)
Fuel Expense  —   (9)  (2)  (11)
                 
2009
                
Gain (Loss) Recognized in AOCL (Effective Portion) $19  $(9) $—  $10 
Effective Gain (Loss) Reclassified to:(1)
                
Purchased Power Expense  (6)  —   —   (6)
Fuel Expense  —   (9)  (10)  (19)
             
Derivatives Not in a Hedging Three Months Ended March 31, 
Relationship with Regulatory Offset(2) NUGs  Other  Total 
  (In millions) 
2011
            
Unrealized Loss to NUG Liability: $(89) $—  $(89)
Unrealized Gain to Regulatory Assets:  89   —   89 
             
Realized Gain to NUG Liability:  72   —   72 
Realized Loss to Regulatory Assets:  (72)  —   (72)
Realized Loss to Deferred Charges  —   (10)  (10)
Realized Gain to Regulatory Assets:  —   10   10 
             
2010
            
Unrealized Loss to NUG Liability: $(224)  —  $(224)
Unrealized Gain to Regulatory Assets:  224   —   224 
 
Realized Gain to NUG Liability:  78   —   78 
Realized Loss to Regulatory Assets:  (78)  —   (78)
Realized Loss to Deferred Charges  —   (9)  (9)
Realized Gain to Regulatory Assets:  —   9   9 
(1) The ineffective portion was immaterial.
             
  Three Months Ended September 30, 
  NUG       
Derivatives Not in Hedging Relationships Contracts  Other  Total 
  (In millions) 
2010
            
Unrealized Gain (Loss) Recognized in:            
Purchased Power Expense $—  $(13) $(13)
Regulatory Assets (2)
  (145)  —   (145)
          
  $(145) $(13) $(158)
          
             
Realized Gain (Loss) Reclassified to:            
Purchased Power Expense $—  $(30) $(30)
Regulatory Assets (2)
  (63)  —   (63)
          
  $(63) $(30) $(93)
          
             
2009
            
Unrealized Gain (Loss) Recognized in:            
Fuel Expense (1)
 $—  $(1) $(1)
Regulatory Assets (2)
  (22)  —   (22)
          
  $(22) $(1) $(23)
          
             
Realized Gain (Loss) Reclassified to:            
Fuel Expense (1)
 $—  $1  $1 
Regulatory Assets (2)
  (93)  —   (93)
          
  $(93) $1  $(92)
          

35

             
  Nine Months Ended September 30, 
  NUG       
Derivatives Not in Hedging Relationships Contracts  Other  Total 
  (In millions) 
2010
            
Unrealized Gain (Loss) Recognized in:            
Purchased Power Expense $—  $(30) $(30)
Regulatory Assets (2)
  (405)  —   (405)
          
  $(405) $(30) $(435)
          
             
Realized Gain (Loss) Reclassified to:            
Purchased Power Expense $—  $(86) $(86)
Regulatory Assets (2)
  (209)  9   (200)
          
  $(209) $(77) $(286)
          
             
2009
            
Unrealized Gain (Loss) Recognized in:            
Fuel Expense (1)
 $—  $2  $2 
Regulatory Assets (2)
  (406)  —   (406)
          
  $(406) $2  $(404)
          
             
Realized Gain (Loss) Reclassified to:            
Fuel Expense (1)
 $—  $—  $— 
Regulatory Assets (2)
  (273)  11   (262)
          
  $(273) $11  $(262)
          
(1)The realized gain (loss) is reclassified upon termination of the derivative instrument.
 
(2) Changes in the fair value of NUGcertain contracts are deferred for future recovery from (or refund to) customers.
Total unamortized losses includedThe following table provides a reconciliation of changes in AOCL associated with commodity derivatives were $8 million ($5 million net of tax) as of September 30, 2010, as compared to $15 million ($9 million net of tax) as of December 31, 2009. The net of tax change resulted from a net $14 million increase related to current hedging activity and a $10 million decrease due to net hedge losses reclassified to earnings during the first nine months of 2010. Based on current estimates, approximately $7 million (net of tax) of the net deferred losses on derivative instruments in AOCL as of September 30, 2010 are expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments fluctuates from period to period based on various market factors.
Many of FirstEnergy’s commodity derivatives contain credit risk features. As of September 30, 2010, FirstEnergy posted $158 million of collateral related to net liability positions and held no counterparties’ funds related to asset positions. The collateral FirstEnergy has posted relates to both derivative and non-derivative contracts. FirstEnergy’s largest derivative counterparties fully collateralize all derivative transactions. Certain commodity derivativecertain contracts include credit risk-related contingent features that would require FirstEnergy to post additional collateral if the credit rating for its debt were to fall below investment grade. The aggregate fair value of derivative instruments with credit risk-related contingent features that are in a liability position on September 30, 2010 was $158 million,deferred for which $192 million in collateral has been posted. If FirstEnergy’s credit rating were to fall below investment grade, it would be required to post $22.5 million of additional collateral related to commodity derivatives.future recover from (or refund to) customers.

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  Three Months Ended March 31, 
Derivatives Not in a Hedging Relationship with Regulatory Offset(1) NUGs  Other  Total 
  (In millions) 
Outstanding net asset (liability) as of January 1, 2011 $(345) $10  $(335)
Additions/Change in value of existing contracts  (89)  —   (89)
Settled contracts  72   (10)  62 
          
Outstanding net asset (liability) as of March 31, 2011 $(362) $—  $(362)
          
             
Outstanding net asset (liability) as of January 1, 2010 $(444) $19  $(425)
Additions/Change in value of existing contracts  (224)  —   (224)
Settled contracts  78   (9)  69 
          
Outstanding net asset (liability) as of March 31, 2010 $(590) $10  $(580)
          

(1)Changes in the fair value of certain contracts are deferred for future recovery from (or refund to) customers.
6. PENSION AND OTHER POSTRETIREMENT BENEFITS
FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and compensation levels.
FirstEnergy 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.

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FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. During the first quarter of 2011, FirstEnergy made a $157 million contribution to its qualified pension plans. FirstEnergy intends to make additional contributions of $220 million and $6 million to its qualified pension plans and postretirement benefit plans, respectively, in the last three quarters of 2011.
FirstEnergy measured the funded status of the Allegheny pension plans and postretirement benefit plans other than pensions as of the merger closing date using discount rates of 5.50% and 5.25%, respectively. As a result of the fair value measurement, FirstEnergy recorded accumulated benefit obligation reductions to the Allegheny pension plans and postretirement benefits other than pensions in the amount of $6 million and $2 million, respectively. The expected returns on plan assets used to calculate net period costs for the month ended March 31, 2011 was 8.25% for the Allegheny qualified pension plan and 5.00% for the Allegheny postretirement benefit plans other than pension plans.
The fair values of plan assets for Allegheny’s pension plans and postretirement benefit plans other than pensions at the date of the merger were $954 million and $75 million, respectively, and the actuarially determined benefit obligations for such plans at that date were $1,341 million and $272 million, respectively.
FirstEnergy’s net pension and OPEB expenseexpenses for the three months ended September 30,March 31, 2011 and 2010 and 2009 was $20were $28 million and $36 million, respectively. FirstEnergy’s net pension and OPEB expense for the nine months ended September 30, 2010 and 2009 was $65 million and $117$24 million, respectively. The components of FirstEnergy’s net pension and other postretirement benefit costsOPEB (including amounts capitalized) for the three and nine months ended SeptemberMarch 30, 20102011 and 2009,2010, consisted of the following:
                        
 Three Months Ended Nine Months Ended  Three Months Ended 
 September September 30  March 31 
Pension Benefit Cost (Credit) 2010 2009 2010 2009  2011 2010 
 (In millions)  (In millions) 
Service cost $25 $23 $74 $66  $29 $25 
Interest cost 79 79 236 239  84 78 
Expected return on plan assets  (90)  (86)  (271)  (248)  (102)  (90)
Amortization of prior service cost 3 3 10 10  4 3 
Recognized net actuarial loss 47 45 141 129  49 47 
Curtailments (1)
  (2) — 
Special termination benefits (1)
 9 — 
              
Net periodic cost $64 $64 $190 $196  $71 $63 
              
(1)Represents costs (credits) incurred related to change in control provision payments to certain executives who were terminated or were expected to be terminated as a result of the merger.
                        
 Three Months Ended Nine Months Ended  Three Months Ended 
 September 30 September 30  March 31 
Other Postretirement Benefit Cost (Credit) 2010 2009 2010 2009  2011 2010 
 (In millions)  (In millions) 
Service cost $2 $15 $7 $23  $3 $2 
Interest cost 11 13 33 51  11 11 
Expected return on plan assets  (9)  (9)  (27)  (27)  (10)  (9)
Amortization of prior service cost  (48)  (48)  (144)  (127)  (48)  (48)
Recognized net actuarial loss 15 15 45 46  14 15 
              
Net periodic cost $(29) $(14) $(86) $(34) $(30) $(29)
              

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Pension and other postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. The net periodic pension costs and net periodic other postretirement benefit costs (including amounts capitalized) recognized by FirstEnergy’s subsidiaries for the three and nine months ended September 30,March 31, 2011 and 2010 and 2009 were as follows:
                        
 Three Months Ended Nine Months Ended  Three Months Ended 
 September 30 September 30  March 31 
Pension Benefit Cost 2010 2009 2010 2009 
Pension Benefit Cost (Credit) 2011 2010 
 (In millions)  (In millions) 
FES $22 $19 $66 $56  $22 $22 
OE 6 6 17 20  5 6 
CEI 5 5 16 14  5 5 
TE 2 2 5 5  1 2 
JCP&L 6 8 19 26  5 6 
Met-Ed 3 5 8 16  3 2 
Penelec 5 4 14 13  5 5 
Other FirstEnergy Subsidiaries 15 15 45 46  25 15 
              
 $64 $64 $190 $196  $71 $63 
              

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 Three Months Ended Nine Months Ended  Three Months Ended 
 September 30 September 30  March 31 
Other Postretirement Benefit Cost (Credit) 2010 2009 2010 2009  2011 2010 
 (In millions)  (In millions) 
FES $(7) $(4) $(20) $(8) $(6) $(7)
OE  (6)  (3)  (19)  (8)  (6)  (6)
CEI  (1) —  (4) 1   (2)  (1)
TE — 1  (1) 2  —  (1)
JCP&L  (2)  (2)  (5)  (4)  (2)  (2)
Met-Ed  (2)  (1)  (6)  (3)  (3)  (2)
Penelec  (2)  (1)  (6)  (2)  (3)  (2)
Other FirstEnergy Subsidiaries  (9)  (4)  (25)  (12)  (8)  (8)
              
 $(29) $(14) $(86) $(34) $(30) $(29)
              
7. VARIABLE INTEREST ENTITIES
FirstEnergy’s consolidated financial statements include the accounts of entities in which it has a controlling financial interest. FirstEnergy consolidates certain VIEs in which it has financial control through disproportionate economics in its equity and debt investments in the entities. These VIEs include: FEV’s joint venture in the Signal Peak mining and coal transportation operations; the PNBV and Shippingport bond trusts that were created to refinance debt originally issued in connection with sale and leaseback transactions; and 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, of which $319 million was outstanding as of September 30, 2010.
FirstEnergy and its subsidiaries reflect the portion of VIEs not owned by them in the caption noncontrolling interest within the consolidated financial statements. The change in noncontrolling interest within the consolidated balance sheets is the result of net losses of the noncontrolling interests ($19 million) and distributions to owners ($5 million) for the nine months ended September 30, 2010.
On January 1, 2010, FirstEnergy adopted the amendments to the consolidation topic addressing VIEs. This standard requires that FirstEnergy and its subsidiaries perform a qualitative analysisanalyses 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. This standard also requires an ongoing reassessment
VIE’s included in FirstEnergy’s consolidated financial statements are: FEV’s joint venture in the Signal Peak mining and coal transportation operations; the PNBV and Shippingport bond trusts that were created to refinance debt originally issued in connection with sale and leaseback transactions; and 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, of which $302 million was outstanding as of March 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 within the consolidated balance sheets is the result of net losses of the primary beneficiary of a VIEnoncontrolling interests ($5 million) and eliminatesdistributions to owners ($3 million) for the quantitative approach previously required for determining whether an entity is the primary beneficiary. There was no impact to FirstEnergy or its subsidiaries as a result of the adoption of this standard.three months ended March 31, 2011.
In order to evaluate contracts under thefor consolidation guidance,treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregated contractsvariable interests into twothe following categories based on similar risk characteristics and significance as follows:

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PATH-WV
PATH, LLC was formed to construct, through its operating companies, a portion of the PATH Project, which is a high-voltage transmission line that is 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, through AE, consists of its equity investment in PATH-WV, which was $26 million at March 31, 2011.
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 the Utilities andif 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 Penelec,MP, maintains 2123 long-term power purchase agreements with NUG entities. The agreements were entered into pursuant to the Public Utility Regulatory Policies Act of 1978.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 twofour of these NUG entities, neither JCP&L, nor Met-Ed nor Penelecits subsidiaries do not have variable interests in the entities or the entities are governmental or not-for-profit organizations that aredo not withinmeet the scope of consolidation consideration for VIEs.criteria to be considered a VIE. JCP&L, PE and WP may hold variable interests in the remaining two entities, which sell their output at variable prices that correlate to some extent with the operating costs of the plants. However,four entities; however, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities.
SinceBecause JCP&L, hasPE and WP have no equity or debt interests in the NUG entities, itstheir maximum exposure to loss relates primarily to the above-market costs it incursincurred for power. FirstEnergy expects any above-market costs it incursincurred by its subsidiaries to be recovered from customers. Purchased power costs related to the four contracts that may contain a variable interest that were held by FirstEnergy subsidiaries during the three months ended March 31, 2011, were $65 million, $11 million and $5 million for JCP&L, PE and WP, respectively. Purchased power costs related to the two contracts that may contain a variable interest that were $73 million and $58 million forheld by JCP&L during the three months ended September 30,March 31, 2010 and 2009, respectively and $190were $64 million.
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 that WP may hold a variable interest, for which WP has taken the scope exception. As of March 31, 2011, WP’s reserve for this adverse purchase power commitment was $61 million, including a current liability of $18 million, and $173 million foris being amortized over the nine months ended September 30, 2010 and 2009, respectively.life of the commitment.

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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.

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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.events. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty events that render the applicable plant worthless.events. 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 September 30, 2010:March 31, 2011:
                        
 Maximum Discounted Lease Net  Maximum Discounted Lease Net 
 Exposure Payments, net(1) Exposure  Exposure Payments, net(1) Exposure 
 (In millions)  (In millions) 
FES $1,376 $1,185 $191  $1,376 $1,187 $189 
OE 672 511 161  644 485 159 
CEI(2)
 627 71 556  664 68 596 
TE(2)
 627 346 281  664 351 313 
(1) The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is $1.7 billion.
 
(2) CEI and TE are jointly and severally liable for the maximum loss amounts under certain sale-leaseback agreements.
8. INCOME TAXES
FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. Accounting guidance prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of tax positions taken or expected to be taken on a company’s tax return. After reachingAs a settlement at appeals in the second quarter of 2010 related primarily to the capitalization of certain costs for the tax years 2005-2008 and a settlement in the third quarter of 2010 of an unrelated federal tax matter related to prior year gains and losses recognized from the disposition of assets, FirstEnergy recognized approximately $78 million of net tax benefits, including $21 million that favorably affected FirstEnergy’s effective tax rate for the first nine months of 2010. The remaining portionresult of the tax benefit increased FirstEnergy’s accumulated deferred income taxes. Upon completion of the federal tax examination for the 2007 tax yearmerger with Allegheny in the first quarter of 2009, FirstEnergy recognized $13 million in2011, FirstEnergy’s unrecognized tax benefits which favorably affected FirstEnergy’s effective tax rate.increased by $97 million. There were no other material changes to FirstEnergy’s unrecognized tax benefits during the first three months of 2011. After reaching a tentative agreement with the IRS on a tax item at appeals related to the capitalization of certain costs in the thirdfirst quarter of 2009.2010, FirstEnergy reduced the amount of unrecognized tax benefits by $57 million, 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 this tax item in the first three months of 2010.
As of September 30, 2010,March 31, 2011, it is reasonably possible that approximately $44$48 million of unrecognized benefits may be resolved within the next twelve months, of which less than $1approximately $6 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 gains and losses from the disposition of assets and the capitalization of certain costs.
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 the third quarter of 2010, approximately $325 million of costs were included as a repair deduction on FirstEnergy’s 2009 consolidatedvarious state tax return, which reduced taxable income and increased the amount of tax refunds that will be applied to FirstEnergy’s 2010 estimated federal tax payments. Due to Pennsylvania’s state flow through tax benefit for this change in accounting, FirstEnergy’s effective tax rate was reduced by $6 million in the third quarter of 2010. In connection with completing FirstEnergy’s 2009 consolidated tax return, FES recognized an $8 million adjustment that increased its income tax expense in the third quarter of 2010. The effects of the adjustment are not material to the quarterly and annual periods in 2009 or for the nine months ended September 30, 2010.items.
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 recognized tax benefits noted above favorably affected FirstEnergy’s effective tax rate by $13 million in the first nine months of 2010. During the first ninethree months of 2009,2011, there were no material changes to the amount of accrued interest, accrued.except for a $6 million increase in accrued interest from Allegheny. The reversal of accrued interest associated with the $57 million in recognized tax benefits in 2010 favorably affected FirstEnergy’s effective tax rate by $5 million in the first quarter of 2010. The net amount of accumulated interest accrued as of September 30, 2010March 31, 2011 was $6$10 million, as compared to $21with $3 million as of December 31, 2009.2010.
As a result of the non-deductible portion of merger transaction costs, FirstEnergy’s effective tax rate was unfavorably impacted by $30 million in the first quarter of 2011.
As a result of the Patient Protection and Affordable Care Act and the Health Care and Education Affordability Reconciliation Act signed into law onin March 23, 2010, and March 30, 2010, respectively, beginning in 2013 the tax deduction 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 areunder prior law were already reflected in FirstEnergy’s consolidated financial statements, the change resulted in a charge to FirstEnergy’s earnings in the first quarter of 2010 of approximately $13 million and a reduction in accumulated deferred tax assets associated with these subsidies. This change reflectsThat charge reflected the anticipated increase in income taxes that will occur as a result of the change in tax law.

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On September 27, 2010,Allegheny recorded as deferred income tax assets the Small Business Jobs Act was signed into law, which extends 50% bonus first-year depreciation for one yeareffect 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. The tax effected net operating loss carryforwards consisted of $152 million of state net operating loss carryforwards that expire from 2019 through 2029 and $53 million of federal net operating loss carryforwards that expire from 2023 to 2010. Management2029. Federal Alternative Minimum Tax credits of $25 million have an indefinite carryforward period.
Allegheny is currently evaluating thisunder audit by the IRS for tax election which could have a material impact on taxable incomeyears 2007 and 2008. The 2009 federal return was filed and is subject to review. State tax returns for 2010tax years 2006 through 2009 remain subject to review in Pennsylvania, West Virginia, Maryland and could increase the amountVirginia for certain subsidiaries of tax refunds to be recognized in 2010 with a corresponding increase to accumulated deferred income taxes for this temporary tax item.
AE. FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS (2008-2010) and state tax authorities. Tax returns for all state jurisdictions are open from 2006-2009. The IRS began reviewing returns for the years 2001-2003 in July 2004 and several items were under appeal. In the fourth quarter of 2009, these items were settled at appeals and sent to Joint Committee on Taxation for final review. The federal audits for years 2004-2006 were completed in the third quarter of 2008 and several items are under appeal. The IRS began auditing the year 2007 in February 2007 under its Compliance Assurance Process program and completed the audit in the first quarter of 2009 with two items under appeal. Items under appeal for tax years 2006 and 2007 were settled and sent to Joint Committee on Taxation for final review in the second quarter and subsequently approved in the third quarter of 2010. The IRS began auditing the year 2008 in February 2008 and the audit was completed in July 2010 with one item under appeal. The 2009 tax year audit began in February 2009 and the 2010 tax year audit began in February 2010. Neither audit is expected to close before December 2010. Management believes that adequate reserves have been recognized and final settlement of these audits is not expected to have a material adverse effect on FirstEnergy’s financial condition or results of operations.

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9. COMMITMENTS, GUARANTEES AND CONTINGENCIES
(A) GUARANTEES AND OTHER ASSURANCES
As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds and LOCs. As of September 30, 2010,March 31, 2011, outstanding guarantees and other assurances aggregated approximately $3.8 billion, consisting primarily of parental guarantees ($0.8 billion), subsidiaries’ guarantees ($2.52.6 billion), surety bonds and LOCs ($0.50.4 billion).
FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate or hedge normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for the financing or refinancing by subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties’ claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy’s guarantee enables the counterparty’s legal claim to be satisfied by other FirstEnergy assets. TheFirstEnergy views as remote the likelihood is remote that such parental guarantees of $0.3$0.2 billion (included in the $0.8 billion discussed above) as of September 30, 2010March 31, 2011 would increase amounts otherwise payable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.
While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event,” the immediate posting of cash collateral, provision of an LOC or accelerated payments may be required of the subsidiary. As of September 30, 2010,March 31, 2011, FirstEnergy’s maximum exposure under these collateral provisions was $419$557 million, consisting of $374$433 million due to a below investment grade credit rating of(of which $175$184 million is due to an acceleration of payment or funding obligation,obligation) and $45$124 million due to “material adverse event” contractual clauses. 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 $511$623 million, consisting of $463$494 million due to a below investment grade credit rating of(of which $175$184 million is related to an acceleration of payment or funding obligation,obligation) and $48$129 million due to “material adverse event” contractual clauses.
Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $84$138 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.
In addition to guarantees and surety bonds, FES’ contracts entered into by the Competitive Energy Services segment, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions whichthat require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ and AE Supply’s power portfolio as of September 30, 2010,March 31, 2011 and forward prices as of that date, FES hasand AE Supply have posted collateral of $244 million.$158 million and $5 million, respectively. 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 $46 million.$52 million of collateral. Depending on the volume of forward contracts and future price movements, FEShigher amounts for margining could be required to post higher amounts for margining.be posted.

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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’ 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 will 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. FirstEnergy, together with WMB Loan Ventures LLC and WMB Loan Ventures II LLC, the entities that share ownership in the borrowers with FEV, have provided a guaranty of the borrowers’ obligations under the facility. In addition, FEV and the other entities that directly own the equity interest in the borrowers have pledged those interests to the lenders under the term loan facility as collateral for the facility.

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(B) 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 SO2SO2 and NOXNOx emissions regulations under the CAA. FirstEnergy complies with SO2 and NOx reduction requirements under the CAA and SIP(s) under the CAA by burning lower-sulfur fuel, combustion controls and post-combustion controls, generating more electricity from lower-emitting plants and/or using emission allowances. Violations can result in the shutdown of the generating unit involved and/or civil or criminal penalties.
The Sammis, Burger, Eastlake and Mansfield coal-fired plants are operated under a consent decree with the EPA and DOJ that requires reductions of NOXNOx and SO2 emissions through the installation of pollution control devices or repowering. OE and Penn are subject to stipulated penalties for failure to install and operate such pollution controls or complete repowering in accordance with that agreement. Capital expenditures necessary to complete requirements of the consent decree, including repowering Burger Units 4 and 5 for biomass fuel combustion, are currently estimated to be approximately $399 million for 2010-2012.
In 2007, PennFutureJuly 2008, three complaints were filed a citizen suit under the CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations,against FGCO in the U.S. District Court for the Western District of Pennsylvania. In July 2008, three additional complaints were filed against FGCOPennsylvania seeking damages based on Bruce Mansfield Plant air emissions. Two of 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 of twenty-one individuals and the other being a class action complaint seeking certification as a class action with the eight named plaintiffs as the class representatives. A settlement was reached with PennFuture. FGCO believes the claims of the remaining plaintiffs are without merit and intends to defend itself against the allegations made in thosethese three complaints.
The states of New Jersey and Connecticut filed CAA citizen suits in 2007 alleging NSR violations at the Portland Generation Station against GenOn Energy, Inc. (formerly RRI Energy, Inc. (theand 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.Energy, and Met-Ed is unable to predict the outcome of this matter.
In January 2009, the EPA issued a NOV to ReliantGenOn Energy, Inc. alleging NSR violations at the Portland Generation Station based on “modifications” dating back to 1986 and also alleged NSR violations at the Keystone and Shawville Stations based on “modifications” dating back to 1984. Met-Ed, JCP&L, as the former owner of 16.67% of the Keystone Station, and Penelec, as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter.
In June 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. (Mission) alleging that “modifications” at the Homer City Power Station occurred sincefrom 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, Energy Westside, Inc., Penelec, New York State Electric & Gas Corporation and others that have had an ownership interest in the Homer City Power Station containing in all material respects allegations identical allegations asto those included in the June 2008 NOV. On July 20, 2010, the states of New York and Pennsylvania provided Mission, Energy Westside, Inc., Penelec, NYSEG and others that have had an ownership interest in the Homer City Power Station a notification that was required 60 days prior to filing a citizen suit under the CAA. 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 the Homer City Power Station 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, New York State Electric and Gas Corporation, and various current owners of the Homer City Station, including EME Homer City Generation L.P. and affiliated companies, including Edison International. 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 the Homer City Station’s air emissions as well as certification as a class action and to enjoin the Homer City Station from operating except in a “safe, responsible, prudent and proper manner.” Penelec believes the claims are without merit and intends to defend itself against the allegations made in the complaint, but, at this time, is unable to predict the outcome of this matter. In addition, the Commonwealth of Pennsylvania and the States of New Jersey and New York intervened and have filed separate complaints regarding the Homer City Station seeking injunctive relief and civil penalties. Mission Energy Westside, Inc. is seeking indemnification from Penelec, the co-owner and operator of the Homer City Power Station prior to its sale in 1999. The scope of Penelec’s indemnity obligation to and from Mission Energy Westside, Inc. is under dispute and Penelec is unable to predict the outcome of this matter.

 

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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 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. FGCO 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 generating plant may constitute a major modification under the NSR provision of the CAA. Later in 2009, FGCO also received another information request regarding emission projections for the Eastlake generating plant. FGCO intends to comply with the CAA, including the EPA’s information requests but, at this time, is unable to predict the outcome of this matter.
In August 2000, AE received a letter from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the following ten electric generation facilities, which collectively include 22 generation units: Albright, Armstrong, Fort Martin, Harrison, Hatfield’s Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island. The letter requested information under Section 114 of the CAA to determine compliance with the CAA and related requirements, including potential application of the NSR standards under the CAA, which can require the installation of additional air emission control equipment when the 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.
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 facilities: 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 generation facilities 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 Hatfield’s Ferry, Armstrong and Mitchell facilities in Pennsylvania. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. In May 2006, the District Court denied Allegheny’s motion to dismiss the amended complaint. In July 2006, the Court determined that discovery would proceed regarding liability issues, but not remedies. Discovery on the liability phase closed on December 31, 2007, and summary judgment briefing was completed during the first quarter of 2008. In November 2008, the District Court issued a Memorandum Order denying all motions for summary judgment and establishing certain legal standards to govern at trial. In December 2009, a new trial judge was assigned to the case, who then entered an order granting a motion to reconsider the rulings in the November 2008 Memorandum Order. In April 2010, the new judge issued an opinion, again denying all motions for summary judgment and establishing certain legal standards to govern at trial. The 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.
In September 2007, Allegheny also 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 Hatfield’s Ferry and Armstrong generation facilities in Pennsylvania and the Fort Martin and Willow Island generation facilities in West Virginia.
FirstEnergy intends to vigorously defend against the CAA matters described above but cannot predict their outcomes.
State Air Quality Compliance
In early 2006, Maryland passed the Healthy Air Act, which imposes state-wide emission caps on SO2 and NOX, requires mercury emission reductions and mandates that Maryland join the RGGI and participate in that coalition’s regional efforts to reduce CO2 emissions. On April 20, 2007, Maryland became the 10th state to join the RGGI. The Healthy Air Act provides a conditional exemption for the R. Paul Smith power station for NOX, SO2 and mercury, based on a PJM declaration that the station is vital to reliability in the Baltimore/Washington DC metropolitan area, which PJM determined in 2006. Pursuant to the legislation, the Maryland Department of the Environment (MDE) passed alternate NOX and SO2 limits 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 of 80% beginning in 2010. The statutory exemption does not extend to R. Paul Smith’s CO2 emissions. Maryland issued final regulations to implement RGGI requirements in February 2008. Ten RGGI auctions have been held through the end of calendar year 2010. 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. FirstEnergy is unable to predict the outcome of this matter.

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In January 2010, the WVDEP issued a NOV for opacity emissions at Allegheny’s Pleasants generating facility. FirstEnergy is discussing with WVDEP steps to resolve the NOV including installing a reagent injection system to reduce opacity.
National Ambient Air Quality Standards
The EPA’s CAIR requires reductions of NOXNOx and SO2 emissions in two phases (2009/2010 and 2015), ultimately capping SO2 emissions in affected states to 2.5 million tons annually and NOXNOx emissions to 1.3 million tons annually. In 2008, the U.S. Court of Appeals for the District of Columbia Circuit 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“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 2010, the EPA proposed the Clean Air Transport Rule (CATR) to replace CAIR, which remains in effect until the EPA finalizes CATR. CATR requires reductions of NOXNOx and SO2 emissions in two phases (2012 and 2014), ultimately capping SO2 emissions in affected states to 2.6 million tons annually and NOXNOx emissions to 1.3 million tons annually. The EPA proposed a preferred regulatory approach that allows trading of NOXNOx and SO2 emission allowances between power plants located in the same state and severely limits interstate trading of NOx and SO2 emission allowances. The EPA also requested comment on two alternative approaches—the first eliminates interstate trading of NOXNOx and SO2 emission allowances and the second eliminates trading of NOXNOx and SO2 emission allowances in its entirety. Depending on the actions taken by the EPA with respect to CATR, the proposed MACT regulations discussed below and any future regulations that are ultimately implemented, FGCO’s future cost of compliance may be substantial. Management is currently assessing the impact of these environmental proposals and other factors on FGCO’s facilities, particularly on the operation of its smaller, non-supercritical units. For example, as disclosed herein, management decided to idle certain units or operate them on a seasonal basis until developments clarify.
Hazardous Air Pollutant Emissions
The EPA’s CAMR provides for a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping nationwide emissions of mercury at 38 tons by 2010 (as a “co-benefit” from implementation of SO2 and NOX emission caps under the EPA’s CAIR program) and 15 tons per year by 2018. The U.S. Court of Appeals for the District of Columbia, at the urging of several states and environmental groups, vacated the CAMR, ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. On April 29, 2010, the EPA issued proposed maximum achievable control technology (MACT) regulations requiring emissions reductions of mercury and other hazardous air pollutants from non-electric generating unit boilers, including boilers which do not use fossil fuels such as the proposed Burger biomass repowering project. On September 1, 2010, the EPA classified Burger as an existing source for purposes of the industrial Boiler MACT. If finalized, the non-electric generating unit MACT regulations could also provide precedent for MACT standards applicable to electric generating units. The EPA entered into a consent decree requiring it to propose MACT regulations for mercury and other hazardous air pollutants from electric generating units by March 16, 2011, the EPA released its MACT proposal to establish emission standards for mercury, hydrochloric acid and to finalize the regulations by November 16, 2011.various metals for electric generating units. Depending on the action taken by the EPA and on how any future regulations are ultimately implemented, FGCO’sFirstEnergy’s future cost of compliance with MACT regulations may be substantial and changes to FGCO’sFirstEnergy’s operations may result.
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, onin June 26, 2009. The Senate continues to consider a number of measures to regulate GHG emissions. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuringproposals to ensure that 10% of electricity used in the United States comes from renewable sources by 2012, increasingto increase to 25% by 2025, and implementingto implement an economy-wide cap-and-trade program to reduce GHG emissions by 80% by 2050. State activities,Certain states, primarily the northeastern states participating in the Regional Greenhouse Gas InitiativeRGGI 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 will requirerequired FirstEnergy to measure GHG emissions commencing in 2010 and will require it to submit reports commencing in 2011. 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 of 75,000 tons per year (tpy) of carbon dioxide equivalents (CO2e) effective January 2, 2011 for existing facilities under the CAA’s PSD program, but untilprogram. Until July 1, 2011, thatthis emissions applicability threshold will only apply if PSD is triggered by non-carbon dioxidenon-CO2 pollutants.

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At the international level, the Kyoto Protocol, signed by the U.S. in 1998 but never submitted for ratification by the U.S. Senate, was intended to address global warming by reducing the amount of 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 below two degrees Celsius; includeincludes a commitment by developed countries to provide funds, approaching $30 billion over the next three years with a goal of increasing to $100 billion by 2020; and establishestablishes the “Copenhagen 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.
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. The U.S. Supreme Court granted a writ of certiorari to review the decision of the Second Circuit. Oral argument was held on April 19, 2011, and a decision is expected by July 2011. While FirstEnergy is not a party to this litigation, FirstEnergy and/or one or more of its subsidiaries could be named in actions making similar allegations.
FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO2 emissions per KWH of electricity generated by FirstEnergy is lower than many 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 Act 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.
The EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing 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). 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. OnIn April 1, 2009, the U.S. Supreme Court reversed one significant aspect of the Second Circuit’s opinion and decided that Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. TheOn March 28, 2011, the EPA is developingreleased a new proposed regulation under Section 316(b) of the Clean Water Act consistent withgenerally requiring fish impingement to be reduced to a 12% annual average and studies to be conducted at the opinionsmajority of the Supreme Courtour existing generating facilities to assist permitting authorities to determine whether and the Courtwhat site-specific controls, if any, would be required to reduce entrainment of Appeals which have created significant uncertainty about the specific nature, scope and timing of the final performance standard.aquatic life. 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. On March 15,In November 2010, the Ohio EPA issued a draft permit for the Bay Shore power plant requiring installation of reverse louvers in its entire water intake channel by December 31, 2014. Depending on the results of such studies and the EPA’s further rulemaking and any final action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

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In June 2008,April 2011, the U.S. Attorney’s Office in Cleveland, Ohio advised FGCO that it is no longer considering prosecution under the Clean Water Act and the Migratory Bird Treaty Act for three petroleum spills at the Edgewater, Lakeshore and Bay Shore plants which occurred on November 1, 2005, January 26, 2007 and February 27, 2007. This matter has been referred back to EPA for civil enforcement and FGCO is unable to predict the outcome of this matter.

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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 Hatfield’s Ferry generation facility. 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 significant costs or negatively affect its ability to operate the scrubbers as designed. Preliminary studies indicate an initial capital investment in excess of $150 million in order to install technology to meet the TDS and sulfate limits in the permit. 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. The hearing is scheduled to begin on September 13, 2011. AE Supply intends to vigorously pursue these issues, but cannot predict the outcome of these appeals.
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 Clean Water Act 303(d) list to the EPA with a recommended sulfate impairment designation for an approximately 68 mile stretch of the Monongahela River north of the West Virginia border. EPA has not acted on PA DEP’s recommendation. If the designation is approved, Pennsylvania will then need to develop a TMDL limit for the river, a process that will take about five years. Based on the stringency of the TMDL, FirstEnergy may incur significant costs to reduce sulfate discharges into the Monongahela River from its Hatfield’s Ferry and Mitchell facilities in Pennsylvania and its Fort Martin facility in West Virginia.
In October 2009, the WVDEP issued the water discharge permit for the Fort Martin generation facility. Similar to the Hatfield’s Ferry water discharge permit issued for the scrubber project, 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 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.
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.
OnIn December 30, 2009, in an advanced 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. OnIn May 4, 2010, the EPA 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. FGCO’sFirstEnergy’s future cost of compliance with any coal combustion residuals 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.

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The UtilitiesUtility Registrants have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the consolidated balance sheet as of September 30, 2010,March 31, 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 $105$104 million (JCP&L — $76$69 million, TE — $1 million, CEI — $1 million, FGCO — $1 million and FirstEnergy — $26$32 million) have been accrued through September 30, 2010.March 31, 2011. Included in the total are accrued liabilities of approximately $67$64 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.
(C) OTHER LEGAL PROCEEDINGS
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. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages due to the outages. After various motions, rulings and appeals, the Plaintiffs’ claims for consumer fraud, common law fraud, negligent misrepresentation, strict product liability and punitive damages were dismissed, leaving only the negligence and breach of contract causes of actions. On July 29, 2010, the Appellate Division upheld the trial court’s decision decertifying the class. Plaintiffs have filed, and JCP&L has opposed, a motion for leave to appeal to the New Jersey Supreme Court. JCP&L is waiting forIn November 2010, the Supreme Court issued an order denying Plaintiffs’ motion. The Court’s decision.
Litigation Relating toorder effectively ends the Proposed Allegheny Energy Merger
In connection with the proposed merger (Note 16), purported shareholders of Allegheny Energy have filed putative shareholder class action and/or derivative lawsuits against Allegheny Energyattempt, and its directors and certain officers, referredleaves only nine (9) plaintiffs to as the Allegheny Energy defendants, FirstEnergy and Merger Sub. Four putative class action and derivative lawsuits were filed in the Circuit Court for Baltimore City, Maryland (Maryland Court). One was withdrawn.pursue their respective individual claims. The Maryland Court has consolidated the remaining three cases under the caption: In re Allegheny Energy Shareholder and Derivative Litigation, C.A. No. 24-C-10-1301. Three shareholder lawsuits were filed in the Court of Common Pleas of Westmoreland County, Pennsylvania and the court has consolidated these actions under the caption: In re Allegheny Energy, Inc. Shareholder Class and Derivative, Litigation, Lead Case No. 1101 of 2010. One putative shareholder class action was filed in the U.S. District Court for the Western District of Pennsylvania and is captioned Louisiana Municipal Police Employees’ Retirement System v. Evanson, et al., C.A. No. 10-319 NBF. In summary, the lawsuits allege, among other things, that the Allegheny Energy directors breachedindividual plaintiffs have not taken any affirmative steps to pursue their fiduciary duties by approving the merger agreement, and that

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Allegheny Energy, FirstEnergy and Merger Sub aided and abetted in these alleged breaches of fiduciary duty. The complaints seek, among other things, jury trials, money damages and injunctive relief. While FirstEnergy believes the lawsuits are without merit and has defended vigorously against the claims, in order to avoid the costs associated with the litigation, the defendants have agreed to the terms of a disclosure-based settlement of all these shareholder lawsuits and have reached agreement with counsel for all of the plaintiffs concerning fee applications. Under the terms of the settlement, no payments are being made by FirstEnergy or Merger Sub. A formal stipulation of settlement was filed with the Maryland Court on October 18, 2010 and agreements have been signed with plaintiffs in the Pennsylvania proceedings to dismiss those actions once the settlement is approved by the Maryland Court. The Maryland judge has preliminarily approved the stipulation of settlement and set the final approval hearing date for December 13, 2010. If the parties are unable to obtain final approval of the settlement, then litigation will proceed, and the outcome of any such litigation is inherently uncertain. If a dismissal is not granted or a settlement is not reached, these lawsuits could prevent or delay the completion of the merger and result in substantial costs to FirstEnergy. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger closes may adversely affect FirstEnergy’s business, financial condition or results of operations.individual claims.
Nuclear Plant Matters
During a planned refueling outage that began on February 28, 2010, FENOC conducted a non destructive examination and testing of the Control Rod Drive Mechanism (CRDM) nozzles of the Davis-Besse reactor pressure vessel head. FENOC identified flaws in CRDM nozzles that required modification. The NRC was notified of these findings, along with federal, state and local officials. On March 17, 2010, the NRC sent a special inspection team to Davis-Besse to assess the adequacy of FENOC’s identification, analyses and resolution of the CRDM nozzle flaws and to ensure acceptable modifications were made prior to placing the RPV head back in service. After successfully completing the modifications, FENOC committed to take a number of corrective actions including strengthening leakage monitoring procedures and shutting Davis-Besse down no later than October 1, 2011, to replace the reactor pressure vessel head with nozzles made of material less susceptible to primary water stress corrosion cracking, further enhancing the safe and reliable operations of the plant. On June 29, 2010, FENOC returned Davis-Besse to service. On September 9, 2010, the NRC held a public exit meeting describing the results of the NRC special inspection team inspection of FENOC’s identification of the CRDM nozzles with flaws and the modifications to those nozzles. On October 22, 2010, the NRC issued its final report of the special inspection. The report contained three findings characterized as very low safety significance that were promptly corrected prior to plant operation.
On April 5, 2010, the Union of Concerned Scientists (UCS) requested that the NRC issue a Show Cause Order, or otherwise delay the restart of the Davis-Besse Nuclear Power Station until the NRC determines that adequate protection standards have been met and reasonable assurance exists that these standards will continue to be met after the plant’s operation is resumed. By a letter dated July 13, 2010, the NRC denied UCS’s request for immediate action because “the NRC has conducted rigorous and independent assessments of returning the Davis-Besse reactor vessel head to service and its continued operation, and determined that it was safe for the plant to restart.” The UCS petition was referred to a petition manager for further review. What additional actions, if any, that the NRC takes in response to the UCS request have not been determined.
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of obligations. As of September 30, 2010,March 31, 2011, FirstEnergy had approximately $2.0$2 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. FirstEnergy provides an additional $15 million parental guarantee associated with the funding of decommissioning costs for these units. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy’s nuclear decommissioning trusts fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy’s 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 nuclear decommissioning trusts. The NRC issued guidance anticipating an increase in low-level radioactive waste disposal costs associated with the decommissioning of FirstEnergy’s nuclear facilities. 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. This estimate encompasses the shortfall covered by the existing $15 million parental guarantee. FENOC agreed to increase the parental guarantee to $95 million within 90 days of the submittal.
In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse Nuclear Power Station operating license for an additional twenty years, until 2037. By an order dated April 26, 2011, the NRC Atomic Safety and Licensing Board (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 regarding (1) a combination of renewable alternatives to the renewal of Davis-Besse’s operating license, and (2) the cost of mitigating a severe accident at Davis-Besse. FENOC is currently evaluating these developments and considering an appropriate response. On April 14, 2011, a group of environmental organizations petitioned the NRC Commissioners to suspend all pending nuclear license renewal proceedings, including the Davis-Besse proceeding, to ensure that any safety and environmental implications of the Fukushima Daiichi Nuclear Power Station event in Japan are considered.
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 failure to begin accepting spent nuclear fuel on January 31, 1998. DOE was required to so commence 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. On January 18, 2011, the parties, FirstEnergy and DOJ, filed a joint status report that established a schedule for the litigation of these claims. FirstEnergy filed damages schedules and disclosures with the DOJ on February 11, 2011, seeking approximately $57 million in damages for delay costs incurred through September 30, 2010. The damage claim is subject to review and audit by DOE.

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Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.
OnIn 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. OnIn March 18, 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, which has not yet rendered an opinion.
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.
FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy’s or its subsidiaries’ financial condition, results of operations and cash flows.

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10. REGULATORY MATTERS
(A) RELIABILITY INITIATIVES
Federally-enforceable mandatory reliability standards apply to the bulk powerelectric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES, FGCO, FENOC, and ATSI.ATSI and TrAIL Company. The NERC, as the ERO is charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including ReliabilityFirstCorporation. All of FirstEnergy’s facilities are located within the ReliabilityFirstregion. FirstEnergy actively participates in the NERC and ReliabilityFirststakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by the ReliabilityFirstCorporation.
FirstEnergy believes that it generally is in compliance with all currently-effective and enforceable reliability standards. FirstEnergy’s practice is to address and resolve any occasional or isolated incidents of noncompliance as they ariseNevertheless, in the normal course of operations.operating its extensive electric utility systems and facilities, FirstEnergy also believesoccasionally 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 ReliabilityFirst. Moreover, it is clear that the NERC, ReliabilityFirstand the FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with new or amended standards cannot be determined at this time; however, 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.
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, that the NERC may take with respect to this matter.
On August 23, 2010, FirstEnergy self-reported to ReliabilityFirsta vegetation encroachment event on a Met-Ed 230 kV line to ReliabilityFirst.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, ReliabilityFirstissued a Notice of Enforcement to investigate the incident. FirstEnergy submitted a data response to ReliabilityFirston September 27, 2010. In March 2011, ReliabilityFirstsubmitted its proposed findings and settlement. At this time, FirstEnergy is evaluating ReliabilityFirst’s proposal and is unable to predict the final outcome of this investigation.
Allegheny has been subject to routine audits with respect to its compliance with applicable reliability standards and has settled certain related issues. In addition, ReliabilityFirstis currently conducting certain violation investigations with regard to matters of compliance by Allegheny.

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(B) MARYLAND
In 1999, Maryland adopted electric industry restructuring legislation, which gave PE’s Maryland retail electric customers the right to choose their electricity generation suppliers. PE remained obligated to provide standard offer generation service (SOS) at capped rates to residential and non-residential customers for various periods. The longest such period, for residential customers, expired on December 31, 2008. PE implemented a rate stabilization plan in 2007 that was designed to transition customers from capped generation rates to rates based on market prices and that concluded on December 31, 2010. PE’s transmission and distribution rates for all customers are subject to traditional regulated utility ratemaking (i.e., cost-based rates).
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 a five-year cycle (to begin in 2008) for the MDPSC to report to the legislature on the status of SOS. In August 2007, PE filed a plan for seeking bids to serve its Maryland residential load for the period after the expiration of rate caps. The MDPSC approved the plan and PE now conducts rolling auctions to procure the power supply necessary to serve its customer load. However, the terms on which PE will provide SOS to residential customers after the settlement beyond 2012 will depend on developments with respect to SOS in Maryland between now and then, 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 and other SOS-related pending proceedings discussed below.
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 August 2010, the MDPSC opened another new proceeding to solicit comments on the PJM RPM process. Public hearings on the comments were held in October 2010. In December 2010, the MDPSC issued an order soliciting comments on a model request for proposal for solicitation of long-term energy commitments by Maryland electric utilities. PE and numerous other parties filed comments, and at this time no further proceedings have been set by the MDPSC in 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, in Maryland, electric consumption be reduced by 10% and electricity demand be reduced by 15%, in each case by 2015. In October 2007, PE filed its initial report on energy efficiency, conservation and demand reduction plans in connection with this order. The MDPSC conducted hearings on PE’s and other utilities’ plans in November 2007 and May 2008.
In a related development, 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, and a pilot deployment of Advanced Utility Infrastructure (AUI) that Allegheny had previously tested in West Virginia. 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 million and would be recovered over the following six years. The AUI pilot was placed on a separate track to be re-examined after further discussion with the Staff of the MDPSC and other stakeholders. Meanwhile, extensive meetings with the MDPSC Staff and other stakeholders to discuss details of PE’s plans for additional and improved programs for the period 2012-2014 began in April 2011.
In March 2009, the Maryland PSC issued an order suspending until further notice 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. PE and several other utilities filed requests for reconsideration of various parts of the order, which were denied. The MDPSC is continuing to conduct hearings and collect data on payment plan and related issues and has adopted a set of proposed regulations that expand the summer and winter “severe weather” termination moratoria when temperatures are very high or very low, from one day, as provided by statute, to three days on each occurrence.

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On March 24, 2011, the MDPSC held an initial hearing to discuss possible new regulations relating to service interruptions, storm response, call center metrics, and related reliability standards. The proposed rules included provisions for civil penalties for non-compliance. Numerous parties filed comments on the proposed rules and participated in the hearing, with many noting issues of cost and practicality relating to implementation. Concurrently, the Maryland legislature is considering a bill addressing the same topics. The final bill passed on April 11, 2011, 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 MDPSC is directed to consider cost-effectiveness, and 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 to assess each utility’s compliance with the standards, and may assess penalties of up to $25,000 per day per violation. The MDPSC has ordered that a working group of utilities, regulators, and other interested stakeholders meet to address the topics of the proposed rules.
In December 2009, PE filed an application with the MDPSC for authorization to construct the Maryland portions of the PATH Project to be owned by PATH Allegheny Maryland Transmission Company, LLC, which is owned by Potomac Edison and PATH-Allegheny. On February 28, 2011, PE withdrew its application. See “Transmission Expansion” in the Federal Regulation and Rate Matters section for further discussion of this matter.
(C) 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 NUG rates and market sales of NUG energy and capacity. As of March 31, 2011, the accumulated deferred cost balance was a credit of approximately $102 million. To better align the recovery of expected costs, in July 2010, JCP&L filed a request to decrease the amount recovered for the costs incurred under the NUG agreements by $180 million annually, which the NJBPU approved, allowing the change in rates to become effective March 1, 2011.
In March 2009 and again in February 2010, JCP&L filed annual SBC Petitions with the NJBPU that included a requested zero level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009 estimated at $736 million (in 2003 dollars). Both matters are currently pending before the NJBPU.
(D) OHIO
The Ohio Companies operate under an Amended ESP, which expires on May 31, 2011, andthat provides for generation supplied through a CBP. The Amended ESP also allows the Ohio Companies to collect a delivery service improvement rider (Rider DSI) at an overall average rate of $0.002 per KWH for the period of April 1, 2009 through December 31, 2011. The Ohio Companies currently purchase generation at the average wholesale rate of a CBP conducted in May 2009. FES is one of the suppliers to the Ohio Companies through the May 2009 CBP. The PUCO approved a $136.6 million distribution rate increase for the Ohio Companies in January 2009, which went into effect on January 23, 2009 for OE ($68.9 million) and TE ($38.5 million) and on May 1, 2009 for CEI ($29.2 million). Applications for rehearing of the PUCO order in the distribution case were filed by the Ohio Companies and one other party. The Ohio Companies raised numerous issues in their application for rehearing related to rate recovery of certain expenses, recovery of line extension costs, the level of rate of return and the amount of general plant balances. The PUCO has not yet issued a substantive Entry on Rehearing.
On October 20, 2009, the Ohio Companies filed an MRO to procure, through a CBP, generation supply for customers who do not shop with an alternative supplier for the period beginning June 1, 2011. The CBP would be similar, in all material respects, to the CBP conducted in May 2009 in that it would procure energy, capacity and certain transmission services on a slice of system basis. However, unlike the May 2009 CBP, the MRO would include multiple bidding sessions and multiple products with different delivery periods for generation supply designed to reduce potential volatility and supplier risk and encourage bidder participation. 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. The PUCO has not yet issued an order in this matter.
OnIn March 23, 2010, the Ohio Companies filed an application for a new ESP.ESP, which the PUCO approved in August 2010, with certain modifications. The new ESP will go into effect on June 1, 2011 and conclude on May 31, 2014. Attached to the application was a Stipulation and Recommendation signed by the Ohio Companies, the Staff of the PUCO, and an additional fourteen parties signing as Signatory Parties, with two additional parties agreeing not to oppose the adoption of the Stipulation. The material terms of the Stipulation includenew ESP include: a CBP similar to the one used in May 2009 and the one proposed inon the October 2009 MRO filing;filing (initial auctions held on October 20, 2010 and January 25, 2011); a load cap of no less than 80%, which also applies to tranches assigned post-auction; a 6% generation discount to certain low-incomelow income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (initial auctions scheduled for October 20, 2010 and January 25, 2011);FES; no increase in base distribution rates through May 31, 2014; load cap of no less than 80%, which also applies to any tranches assigned post auction; and a new distribution rider, Delivery Capital Recovery Rider (Rider DCR), to recover a return of, and on, capital investments in the delivery

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system. This Rider DCR substitutes for Rider DSI which terminates by its own terms.under the current ESP. The Ohio Companies also agreeagreed not to collect certain amounts associated with RTEP and administrative costs associated with the move to PJM, dependent on the outcome of certain PJM proceedings. Many of the existing riders approved in the previous ESP remain in effect, some with modifications. The new ESP also requests the resolution of current proceedings pending at the PUCO regarding corporate separation, elements of the smart grid proceeding and the move to PJM. FirstEnergy recorded approximately $39.5 million of regulatory asset impairments and expenses related to the ESP. On May 12, 2010, a supplemental stipulation was filed that added two additional parties to the Stipulation, namely the City of Akron, Ohio and Council for Smaller Enterprises, to provide additional energy efficiency benefits. On July 22, 2010, a second supplemental stipulation was filed that, among other provisions provides a commitment thatrecover from retail customers of the Ohio Companies will not pay certain costs related to the companies’ integration into PJM for the longer of the five yearfive-year period from June 1, 2011 through May 31, 20162015 or when the amount of costs avoided by customers for certain types of products totals $360 million dependent on the outcome of certain PJM proceedings, and establishesagreed to establish a $12 million fund to assist low income customers over the term of the ESP. Additional parties signing or not opposingESP and agreed to additional matters related to energy efficiency and alternative energy requirements. Many of the second supplemental stipulation include Northeast Ohio Public Energy Council (NOPEC), Northwest Ohio Aggregation Coalition (NOAC), Environmental Law and Policy Center and a number of low income community agencies.existing riders approved in the previous ESP remain in effect, with some modifications. The PUCO modified and approved the new ESP on August 25, 2010. The Companies acceptedresolved proceedings pending at the PUCO’s decision subject to the implementation of certainPUCO regarding corporate separation, elements of the ESP being consistent withsmart grid proceeding and expenses related to the terms as they were included in the stipulation. On September 24, 2010, an application for rehearing was filed by the OCC and two other parties. The Ohio Companies and other parties filed their memorandum contra to that application for rehearing on October 4, 2010. The PUCO granted the application for rehearing on October 22, 2010. The PUCO has yet to rule on the substance of the application for rehearing.ESP.
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 approximately 166,000 MWH in 2009, 290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in 2012 and 530,000 MWH in 2013, with additional savings required through 2025. Utilities are also required to reduce peak demand in 2009 by 1%, with an additional 0.75% reduction each year thereafter through 2018. The Ohio Companies filed an application with the PUCO seeking amendments to these benchmarks. On January 7, 2010, the PUCO amended the Ohio Companies’ 2009 energy efficiency benchmarks to zero, contingent upon the Ohio Companies meeting the revised benchmarks in a period of not more than three years. On March 10, 2010, the PUCO found that the Ohio Companies’ peak demand reduction programs complied with PUCO rules.

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On
In December 15, 2009, the Ohio Companies filed the required three year portfolio plan seeking approval for the programs they intend to implement to meet the energy efficiency and peak demand reduction requirements for the 2010-2012 period. On March 8, 2010, the Ohio Companies filed their 2009 Status Update Report with the PUCO in which they indicated compliance with the 2009 statutory energy efficiency and peak demand benchmarks as those benchmarks were amended as described above. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers. The PUCO issued an Opinion and Order generally approving the Ohio Companies’ three year portfolio3-year plan, is still awaiting decision fromand the PUCO. The plan has yet to be approved byCompanies are in the PUCO, which is delayingprocess of implementing those programs included in the Plan. Because of the delay in issuing the Order, the launch of the programs describedincluded in the plan. Without such approval,plan for 2010 was delayed and will launch during the Ohiosecond quarter of this year. As a result, OE fell short of its statutory 2010 energy efficiency and peak demand reduction benchmarks. 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 Companies’ compliance with 2010 (and 2011 and 2012) energy efficiency benchmarks is jeopardized and if not approved soon may requirewhen addressing the portfolio plan, the Ohio Companies to seekwere 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 these them into compliance with their annual benchmark requirements for 2010.yet-to-be-defined modified benchmarks. Failure to comply with the benchmarks or to obtain such an amendment may subject the Companies to an assessment by the PUCO of a forfeiture.penalty. In addition to approving the programs included in the plan, with only minor modifications, the PUCO authorized the 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 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.
Additionally under SB221, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they served in 2009. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RFPs sought RECs, including solar RECs and RECs generated in Ohio in order to meet the Ohio Companies’ alternative energy requirements as set forth in SB221 for 2009, 2010 and 2011. The RECs acquired through these two RFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. OnIn March 10, 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market. The PUCO reduced the Ohio Companies’ aggregate 2009 benchmark to the level of solar RECs the Ohio Companies acquired through their 2009 RFP processes, provided the Ohio Companies’ 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC benchmark. On April 15, 2010, the Ohio Companies and FES (due to its status as an electric service company in Ohio) filed compliance reports with the PUCO setting forth how they individually satisfied the alternative energy requirements in SB221 for 2009. FES also applied for a force majeure determination from the PUCO regarding a portion of their compliance with the 2009 solar energy resource benchmark. On February 23, 2011, the PUCO granted FES’ force majeure request for 2009 and increased its 2010 benchmark which application is still pending.by the amount of SRECs that FES was short of in its 2009 benchmark. In July 2010, the Ohio Companies initiated an additional RFP to secure RECs and solar RECs needed to meet the Ohio Companies’ alternative energy requirements as set forth in SB221. As a result of this RFP,SB221 for 2010 and 2011 and executed related contracts were executed in August 2010. 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. The PUCO has not yet acted on that application.
OnIn February 12, 2010, OE and CEI filed an application with the PUCO to establish a new credit for all-electric customers. OnIn March 3, 2010, the PUCO ordered that rates for the affected customers be set at a level that will provide bill impacts commensurate with charges in place on December 31, 2008 and authorized the Ohio Companies to defer incurred costs equivalent to the difference between what the affected customers would have paid under previously existing rates and what they pay with the new credit in place. Tariffs implementing this new credit went into effect onin March 17, 2010. OnIn April 15, 2010, the PUCO issued a Second Entry on Rehearing that expanded the group of customers to which the new credit would apply and authorized deferral for the associated additional amounts. The PUCO also stated that it expected that the new credit would remain in place through at least the 2011 winter season, and charged its staff to work with parties to seek a long term solution to the issue. Tariffs implementing this newly expanded credit went into effect in May 2010 and the proceeding remains open. The hearing on May 21, 2010.the matter was held in February 2011. The matter has now been briefed and the Ohio Companies also filed on May 14, 2010 an application for rehearing ofawait the Second Entry on Rehearing, which was granted for purposes of further consideration on June 9, 2010. On September 9, 2010, the OCC filed a motion requesting that a procedural schedule be established. The Ohio Companies filed their motion contra on September 23, 2010. The PUCO Staff issued a report related to the all-electric issue on September 24, 2010, in which it provides background on the issue and sets forth its bill impact analysis under a number of different scenarios for a longer term solution, but it made no specific recommendation to the PUCO.PUCO’s decision.

 

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(C)(E) PENNSYLVANIA
Met-Ed and Penelec purchase a portion of their POLR 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 POLR and default service obligations.
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, with 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, reflecting the settlement on all but 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.
On February 8, 2010, Penn filed a Petition for Approval of its Default Service Plan for the period June 1, 2011 through May 31, 2013. On July 29, 2010, the parties to the proceeding filed a Joint Petition for Settlement of all issues. The PPUC adopted a Motion approving the Joint Petition for Settlement on October 21, 2010. The Joint Petition resolves all issues relating to Penn’s Default Service Plan for the next program period, including its procurement method, compliance with the Alternative Energy Portfolio Standards Act, rate design and retail market issues. The PPUC’s approval of the Joint Petition is conditioned by holding that the provision relating to the recovery of MISO exit cost fees and one-time PJM integration costs (resulting from Penn’s June 1, 2011 exit of MISO and integration into PJM) be approved, but made subject to the approval of cost recovery by FERC. Penn may not put these provisions into effect until FERC has approved the recovery and allocation of MISO exit fees and PJM integration costs. An Order consistent with the Motion is expected to be entered in the near future.
The PPUC adopted a Motion on January 28, 2010 and subsequently entered an Order on March 3, 2010 which deniesthat denied the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, and directsdirected Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructsinstructed 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 ratepayers plus interest to be used to mitigate future generation rate increases beginning January 1, 2011. OnIn March 18, 2010, Met-Ed and Penelec filed a Petition with the PPUC requesting that it stay the portion of the March 3, 2010 Order requiring the filing of tariff supplements to end collection of costs for marginal transmission losses. By Order entered March 25, 2010, theThe PPUC granted the requested stay until December 31, 2010. Pursuant to the PPUC’s order, Met-Ed and Penelec filed the planplans to establish separate accounts for marginal transmission loss revenues and related interest and carrying charges and the plan for the use of these funds to mitigate future generation rate increases commencing January 1, 2011. Thewhich the PPUC approved this plan on June 7, 2010. Onapproved. In April 1, 2010, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania appealing the PPUC’s March 3, 2010 Order. The argument before the Commonwealth Court, en banc, was held in December 2010. Although the ultimate outcome of this matter cannot be determined at this time, it is the belief of Met-Ed and Penelec believe that they should prevail in the appeal and therefore expect to fully recover the approximately $199.7$252.7 million ($158.5188.0 million for Met-Ed and $41.2$64.7 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011. On July 9, 2010, Met-Ed
In May 2008, May 2009 and Penelec filed their briefs with the Commonwealth Court of Pennsylvania. The Office of Small Business Advocate filed its brief on July 9, 2010. On August 24, 2010, the PPUC as well as MEIUG and PICA filed their briefs. Met-Ed and Penelec filed their reply brief on September 9, 2010.
On May 20, 2010, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider for the periodannual periods between June 1, 2010 through2008 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 was increased to provide for full recovery by December 31, 2010.
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 through a prudent mix of long-term, short-term and spot market generation supply with a staggered procurement schedule that varies by customer class, using a descending clock auction. In August 2009, the parties to the proceeding filed a settlement agreement of all but two issues, and the PPUC entered an Order approving the settlement and the generation procurement plan in November 2009. Generation procurement began in January 2010.
In February 2010, Penn filed a Petition for Approval of its Default Service Plan 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 was enacted in 2008 to address issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters; and alternative energy. Among other things, Act 129 required utilities to file with the PPUC an energy efficiency and peak load reduction plan, or EE&C Plan, by July 1, 2009, setting forth the utilities’ plans to reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of 4.5% by May 31, 2013. Act 129 also required utilities to file with the PPUC a Smart Meter Implementation Plan (SMIP).
The PPUC entered an Order onin February 26, 2010 approvinggiving final approval to all aspects of the Pennsylvania Companies’ EE&C Plans of Met-Ed, Penelec and Penn and the tariff rider with rates effective March 1, 2010.
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 November 2009, the Office of Consumer Advocate (OCA) filed an appeal with the Commonwealth Court of the PPUC’s October Order. The OCA contends that the PPUC’s Order failed to include WP’s costs for smart meter implementation in the EE&C Plan, and that inclusion of such costs would cause the EE&C Plan to exceed the statutory cap for EE&C expenditures. The OCA also contends that WP’s EE&C plan does not meet the Total Resource Cost Test. The appeal remains pending but has been stayed by the Commonwealth Court pending possible settlement of WP’s SMIP. 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.

 

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Met-Ed, Penelec and Penn jointly filed a Smart Meter Technology Procurement and Installation PlanSMIP with the PPUC.PPUC in August 2009. This plan proposesproposed 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 atof approximately $29.5 million, which the Pennsylvania Companies, in their plan, proposed to recover through an automatic adjustment clause. The ALJ’s Initial Decision approved the Smart Meter PlanSMIP as modified by the ALJ, including: ensuring that the smart meters to be deployed include the capabilities listed in the PPUC’s Implementation Order; eliminatingdenying the provisionrecovery of interest inthrough the 1307(e) reconciliation;automatic adjustment clause; providing for the recovery of reasonable and prudent costs minusnet of resulting savings from installation and use of smart meters; and reflectingrequiring that administrative start-up costs be expensed and the costs incurred for research and development in the assessment period be capitalized. OnIn April 15, 2010, the PPUC adopted a Motion by Chairman Cawley that modified the ALJ’s initial decision, and decided various issues regarding the Smart Meter Implementation PlanSMIP for the Pennsylvania Companies.Met-Ed, Penelec and Penn. The PPUC entered its Order onin June 9, 2010, consistent with the Chairman’s Motion. On June 24, 2010, Met-Ed, Penelec and Penn filed a Petition for Reconsideration of a single portion of the PPUC’s Order regarding the future ability to include smart meter costs in base rates. On August 5, 2010,rates, which the PPUC granted in part the petition for reconsideration by deleting language from its original order that would have precluded Met-Ed, Penelec and Penn from seeking to include smart meter costs in base rates at a later time. The costs to implement the SMIP could be material. However, assuming these costs satisfy a just and reasonable standard, they are expected to be recovered in a rider (Smart Meter Technologies Charge Rider) which was approved when the PPUC approved the SMIP.
In August 2009, WP filed its original SMIP, which provided for extensive deployment of smart meter infrastructure with replacement of all of WP’s approximately 725,000 meters by the end of 2014. 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 an Initial Decision dated April 29, 2010, an ALJ determined that WP’s alternative smart meter deployment plan, which contemplated deployment of 375,000 smart meters by May 2012, complied with the requirements of Act 129 and recommended approval of the alternative plan, including WP’s proposed cost recovery mechanism.
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 Office of Consumer Advocate 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 approximately 25,000 smart 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 the 30-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.
In December 2010, the PPUC directed that the SMIP proceeding be referred to the ALJ for further proceedings to ensure that the impact of the proposed merger with FirstEnergy is considered and that the Joint Petition for Settlement has adequate support in the record. 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. The proposed settlement also obligates OCA to withdraw its November 2009 appeal of the PPUC’s Order in WP’s EE&C plan proceeding. A Joint Stipulation with the OSBA was also filed on March 9, 2011. The proposed settlement remains subject to review by the ALJ, who will prepare an Initial Decision for consideration by the PPUC.
By Tentative Order entered in September 17, 2009, the PPUC provided for an additional 30-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 above accounting method utilized by Met-Ed and Penelec. Met-Ed and Penelec are awaiting further action by the PPUC.
(D) NEW JERSEY
JCP&L is permittedIn 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 defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers, costs incurred under NUG agreements,ensure that a properly functioning and certain other stranded costs, exceed amounts collected through BGS and NUGC rates andworkable competitive retail electricity market sales of NUG energy and capacity. As of September 30, 2010, the accumulated deferred cost balance was a credit of approximately $3 million. To better align the recovery of expected costs, on July 26, 2010, JCP&L filed a request to decrease the amount recovered for the costs incurred under the NUG agreements by $180 million annually. If approved as filed, the change would not go into effect until January 1, 2011.
In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004, supporting continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The DPA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. JCP&L responded to additional NJBPU staff discovery requests in May and November 2007 and also submitted commentsexists in the proceeding in November 2007. A schedule for further NJBPU proceedingsstate. The PPUC has not yet been set. On March 13, 2009, JCP&L filed its annual SBC Petition with the NJBPUinitiated 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 estimated at $736 million (in 2003 dollars). This matter is currently pending before the NJBPU.
New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The 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. On April 16, 2010, the NJBPU issued an order indefinitely suspending the requirement of New Jersey utilities to submit Utility Master Plans until such time as the status of the EMP has been made clear. At this time, FirstEnergy and JCP&L cannot determine the impact, if any, the EMP may have on their operations.
In support of 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. On July 6, 2010, the January 30, 2009 petition directed to infrastructure investment which had been pending before the NJBPU was withdrawn by JCP&L. Implementation of the remaining projects is dependent upon resolution of regulatory issues including recovery of the costs associated with the proposal.investigation.

 

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(E)(F) VIRGINIA
In September 2010, PATH-VA filed an application with the Virginia SCC for authorization to construct the Virginia portions of the PATH Project. On February 28, 2011, PATH-VA filed a motion to withdraw the application. See “Transmission Expansion” in the Federal Regulation and Rate Matters section for further discussion of this matter.
(G) WEST VIRGINIA
In August 2009, MP and PE filed with the WVPSC a request to increase retail rates by approximately $122.1 million annually, effective June 10, 2010. In January 2010, MP and PE filed supplemental testimony discussing a tax treatment change that would result in a revenue requirement approximately $7.7 million lower than the requirement included in the original filing. In addition, in December 2009, subsidiaries of MP and PE completed a securitization transaction to finance certain costs associated with the installation of scrubbers at the Fort Martin generating station, which costs would otherwise have been included in the request for rate recovery. Consequently, MP and PE ultimately requested an annual increase in retail rates of approximately $95 million, rather than $122.1 million. In April 2010, MP and PE filed with the WVPSC a Joint Stipulation and Agreement of Settlement reached with the other parties in the proceeding that provided for:
a $40 million annualized base rate increase effective June 29, 2010;
a deferral of February 2010 storm restoration expenses in West Virginia over a maximum five-year period;
an additional $20 million annualized base rate increase effective in January 2011;
a decrease of $20 million in ENEC rates effective January 2011, which amount is deferred for later recovery in 2012; and
a moratorium on filing for further increases in base rates before December 1, 2011, except under specified circumstances.
The WVPSC approved the Joint Petition and Agreement of Settlement in June 2010.
In 2009, the West Virginia Legislature enacted the Alternative and Renewable Energy Portfolio Act (Portfolio Act), 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, including ten percent by 2015, fifteen percent by 2020, and twenty-five percent by 2025. In November 2010, the WVPSC issued Rules Governing Alternative and Renewable Energy Portfolio Standard (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. Additionally, in January 2011, MP and PE filed an application with the WVPSC seeking to certify three  facilities as Qualified Energy Resource Facilities. If the application is approved, the three facilities would then be capable of generating renewable credits which would assist the companies in meeting their combined requirements under the Portfolio Act. Further, in February 2011, MP and PE filed a petition with the WVPSC seeking an Order declaring that MP is entitled to all alternative & 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 WV. The City of New Martinsville, the owner of one of the contracted resources, has filed an opposition to the Petition.

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(H) FERC MATTERS
Rates for Transmission Service Between MISO and PJM
In November 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 SECA) during a 16-month transition period. In 2005, the FERC set the SECA for hearing. The presiding ALJ issued an initial decision in August 2006, rejecting the compliance filings made by MISO, PJM and the transmission owners, and directing new compliance filings. This decision was subject to review and approval by the FERC. In May 2010, FERC issued an order denying pending rehearing requests and an Order on Initial Decision which reversed the presiding ALJ’s rulings in many respects. Most notably, these orders affirmed the right of transmission owners to collect SECA charges with adjustments that modestly reduce the level of such charges, and changes to the entities deemed responsible for payment of the SECA charges. The Ohio Companies were identified as load serving entities responsible for payment of additional SECA charges for a portion of the SECA period (Green Mountain/Quest issue). FirstEnergy executed settlements with AEP, Dayton and the Exelon parties to fix FirstEnergy’s liability for SECA charges originally billed to Green Mountain and Quest for load that returned to regulated service during the SECA period. The AEP, Dayton and Exelon, settlements were approved by the FERC in November 2010, and the relevant payments made. The Utilities have refund obligations that are under review by FERC as part of a compliance filing. Potential refund obligations of FirstEnergy are not expected to be material. Rehearings remain pending in this proceeding.
PJM Transmission Rate
OnIn April 19, 2007, 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, 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 based on the amount of load served in a transmission zone. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a load flow methodology (DFAX), which is generally referred to as a “beneficiary pays” approach to allocating the cost of high voltage transmission facilities.
The FERC’s Opinion 494 order was appealed to the U.S. Court of Appeals for the Seventh Circuit, which issued a decision onin August 6, 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 new 500+ kV facilities on a load ratio share basis and, based on this finding, remanded the rate design issue back to FERC.
In an order dated January 21, 2010, FERC set the matter for “paper hearings”—meaning that FERC called for parties to submit comments or written testimony pursuant to the schedule described in the order. FERC identified nine separate issues for comments and directed PJM to file the first round of comments on February 22, 2010, with other parties submitting responsive comments and thethen reply comments.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 eastern utilities in PJM bearing the majority of theirthe costs. Numerous parties filed responsive comments or studies on May 28, 2010 and reply comments on June 28, 2010. FirstEnergy and a number of other utilities, industrial customers and state commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. Certain eastern utilities and their state commissions supported continued socialization of these costs on a load ratio share basis. FERCThis matter is expected to act beforeawaiting action by the end of the year.FERC.
RTO ConsolidationRealignment
On December 17, 2009,February 1, 2011, ATSI in conjunction with PJM filed its proposal with FERC issued an order approving, subjectfor moving its transmission rate into PJM’s tariffs. FirstEnergy expects ATSI to certain future compliance filings, ATSI’s move to PJM. This move, which is expected to be effectiveenter PJM on June 1, 2011, allowsand that if legal proceedings regarding its rate are outstanding at that time, ATSI will be permitted to start charging its proposed rates, subject to refund. On April 1, 2011, the MISO Transmission Owners (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, to consolidate its transmission assets and operations into PJM. Currently, FirstEnergy’s transmission assets and operations are divided between PJM and MISO. The consolidation will make the transmission assets that are part of ATSI, whose footprint includes the Ohio Companies and Penn, part of PJM. In the order, FERC approved FirstEnergy’s proposal to use a Fixed Resource Requirement Plan (FRR Plan) to obtain capacity to satisfy the PJM capacity requirementsMISO submitted numerous filings for the 2011-12 and 2012-13 delivery years.
On December 17, 2009, ATSI executed the PJM Consolidated Transmission Owners Agreement and on December 18, 2009, the Ohio Companies and Penn executed the PJM Operating Agreement and the PJM Reliability Assurance Agreement. Executionpurpose of these agreements committed ATSI, the Ohio Companies and Penn to the move into PJM.
FirstEnergy successfully conducted the FRR auctions on March 19, 2010. Moreover, the ATSI-zone loads participated in the PJM base residual auction for the 2013 delivery year. Successful completioneffecting movement of these steps secured the capacity necessary for the ATSI footprintzone to meet PJM’s capacity requirements.
On September 4, 2009,PJM on June 1, 2011. These filings include clean-up of the PUCO opened a caseMISO’s tariffs (to remove the ATSI zone), submission of load and generation interconnection agreements to take comments from Ohio’s stakeholders regarding the RTO consolidation. On August 25, 2010, the PUCO issued an order that, among other things, committed the PUCO to close this case and also to withdraw its objections that were filed in the relevant FERC dockets conditioned upon the Ohio Companies not seeking recovery of MISO exit fees or PJM integration costs (estimated to be approximately $37 million as of September 30, 2010). Notwithstanding the PUCO’s actions, certain other parties protested aspects ofreflect the move into PJM, and certainsubmission of changes to PJM’s tariffs to support the move into PJM.
FERC proceedings are pending in which ATSI’s transmission rate, the exit fee payable to MISO, transmission cost allocations and costs associated with long term firm transmission rights payable by the ATSI zone upon its departure from the MISO are under review. The outcome of these matters remain outstanding and willproceedings cannot be resolved in future FERC proceedings. Under the terms of the ESP order issued on August 25, 2010, the PUCO has agreed to close this docket.predicted.

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MISO Multi-Value Project Rule Proposal
OnIn July 15, 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 Multi-Value Projects (MVPs)—MVPs—are a class of MTEP projects. The MISO proposesfiling 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. MISO expectsThe filing parties expect that itsthe 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. MISO hasThe filing parties requested that FERC rule on its MVP proposal by December, but has asked for an effective date for itsthe proposal of July 16, 2011. On August 19, 2010, MISO’s Board approved the first MVP project—project — the so-called “Michigan Thumb Project.” Under MISO’s proposal, the costs of MVP projects approved by MISO’s Board prior to the anticipated June 1, 2011 effective date of FirstEnergy’s integration into PJM would continue to be allocated to FirstEnergy. This approach is reflected in the MISO’sMISO estimated allocations of the costs for the Michigan Thumb Project, wherethat approximately $16$15 million in annual revenue requirements werewould be allocated to the ATSI zone.zone associated with the Michigan Thumb Project upon its completion.

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OnIn September 10, 2010, FirstEnergy filed a protest to MISO’sthe MVP proposal. FirstEnergy believesproposal arguing that MISO’s proposal to allocate costs of MVP 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 to date in the ATSI move tointegration 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. FERC’s order was not clear, however, as to 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 attach 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 filed for rehearing of FERC’s order. In its rehearing request, FirstEnergy argued that because the MVP rate is unableusage-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. FirstEnergy cannot predict the outcome of these proceedings at this time.
PJM Calculation Error
In March 2010, MISO filed two complaints at FERC against PJM relating to a previously-reported modeling error in PJM’s system that impacted the manner in which market-to-market power flow calculations were made between PJM and MISO since April 2005. MISO claimed that this error resulted in PJM underpaying MISO by approximately $130 million over the time period in question. Additionally, MISO alleged that PJM did not properly trigger market-to-market settlements between PJM and MISO during times when it was required to do so, which MISO claimed may have cost it $5 million or more. As PJM market participants, AE Supply and MP may be liable for a portion of any refunds ordered in this case. PJM, Allegheny and other PJM market participants filed responses to MISO complaints and PJM filed a related complaint at FERC against MISO claiming that MISO improperly called for market-to-market settlements several times during the same time period covered by the two MISO complaints filed against PJM, which PJM claimed may have cost PJM market participants $25 million or more. On January 4, 2011, an Offer of Settlement was filed at FERC that, if approved, would resolve all pending issues in the dispute. The Offer of Settlement calls for the withdrawal of all pending complaints with no payments being made by any parties. Initial comments on the Offer of Settlement were filed at FERC on January 24, 2011. FirstEnergy and Allegheny Energy filed comments supporting the proposed settlement. A report on the partially contested settlement was issued by the settlement judge to the FERC on March 9, 2011. On March 16, 2011, the settlement judge terminated the settlement proceedings and forwarded the partially contested settlement to the FERC for review. The case is awaiting a decision by the FERC.
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 California Department of Water Resources (CDWR) during 2001. The settlement proposal claims that CDWR is owed approximately $190 million for these alleged overcharges. This proposal was made in the context of mediation efforts by the 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 remanded one of those proceedings to the FERC, which arises out of claims previously filed with the 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 have 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. In April 2010, the California parties filed exceptions to the judge’s ruling with the FERC, and briefing is complete on those exceptions. The parties are awaiting a ruling from the FERC on the exceptions.

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In June 2009, the California Attorney General, on behalf of certain California parties, filed a second lawsuit with the 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 the joining of AE Supply in this new lawsuit. AE Supply has filed a motion to dismiss the Brown case that is pending before the FERC. No scheduling order has been entered in the Brown case. Allegheny intends to vigorously defend against these claims but cannot predict their outcome.
Transmission Expansion
TrAIL Project.TrAIL is a 500kV transmission line currently under construction that will extend from southwest Pennsylvania through West Virginia and into northern Virginia. On April 15, 2011, the TrAIL 500 kV line segment from Meadowbrook substation to Loudoun substation in Virginia was successfully energized and is carrying load. The other segments are planned to be energized in May. The entire TrAIL line is scheduled to be completed and placed in service no later than June 2011.
PATH Project.The PATH Project is comprised of a 765 kV transmission line that is 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 and, on June 17, 2010, requested that PATH, LLC proceed with all efforts related to the PATH Project, including state regulatory proceedings, assuming a required in-service date of June 1, 2015. 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 potential 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 and the WVPSC has granted the motion to withdraw. The VSCC has not ruled on the motion to withdraw.
PATH, LLC 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 return on equity 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 a 1.5% return on equity incentive adder and a 0.50% return on equity adder for RTO participation. These adders will be applied to the base return on equity determined as a result of the hearing. PATH, LLC is currently engaged in settlement discussions with the staff of FERC and intervenors regarding resolution of the base return on equity. FirstEnergy cannot predict the outcome of this matter.proceeding or whether it will have a material impact on its operating results.
Sales to Affiliates
FES has received authorization from the FERC to make wholesale power sales to affiliated regulated utilities in New Jersey, Ohio, and Pennsylvania. FES actively participates in auctions conducted by or on behalf the regulated affiliates to obtain power necessary to meet the utilities’ POLR obligations. AE Supply, a merchant affiliate acquired in the FirstEnergy-Allegheny merger, also participates in these auctions, and obtains prior FERC authorization when necessary to make sales to FE affiliates.
11. STOCK-BASED COMPENSATION PLANS
FirstEnergy has four types of stock-based compensation programs including LTIP, EDCP, ESOP and DCPD, as described below.
In addition, Allegheny’s stock-based awards were converted into First Energy stock-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 where applicable, the exercise price thereof, to reflect the merger’s common stock exchange ratio of 0.667 of a share of FirstEnergy common stock for each share of Allegheny common stock.

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(A) LTIP
FirstEnergy’s LTIP includes four forms of stock-based compensation awards — stock options, performance shares, restricted stock and restricted stock units.
Under FirstEnergy’s 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 be settled in common stock, with vesting periods ranging from two months to ten 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. There were 6.3 million shares available for future awards as of March 31, 2011.
Restricted Stock and Restricted Stock Units
Restricted common stock (restricted stock) and restricted stock unit (stock unit) activity was as follows:
Three Months
Ended
March 31, 2011
Restricted stock and stock units outstanding as of January 1, 20111,878,022
Granted223,161
Converted Allegheny restricted stock645,197
Exercised(422,031)
Forfeited(37,182)
Restricted stock and stock units outstanding as of March 31, 20112,287,167
The 223,161 shares of restricted common stock granted during the three months ended March 31, 2011 had a grant-date fair value of $8.2 million and a weighted-average vesting period of 1.86 years.
Restricted stock units include awards that will be settled in a specific number of shares of stock after the service condition has been met. Restricted stock units also include performance-based awards that will be settled after the service condition has been met in a specified number of shares of stock based on FirstEnergy’s performance compared to annual target performance metrics.
Compensation expense recognized for the three months ended March 31, 2011 and 2010 for restricted stock and restricted stock units, net of amounts capitalized, was approximately $16 million and $6 million, respectively.
Stock Options
Stock option activity for the three months ended March 31, 2011 was as follows:
         
      Weighted 
      Average 
  Number of  Exercise 
Stock Option Activities Shares  Price 
 
Stock options outstanding as of January 1, 2011 (all exercisable)  2,889,066  $35.18 
Options granted  662,122   37.75 
Converted Allegheny options  1,805,811   41.75 
Options exercised  (182,422)  29.56 
Options forfeited/expired  (6,670)  69.36 
       
Stock options outstanding as of March 31, 2011  5,167,907  $37.96 
       
(4,505,785 options exercisable)        
Compensation expense recognized for stock options during the three months ended March 31, 2011 was $0.1 million. No expense was recognized during the three months ending March 31, 2010. Options granted during the three months ended March 31, 2011 had a grant-date fair value of $3.3 million and an expected weighted-average vesting period of 3.79 years.

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Options outstanding by exercise price as of March 31, 2011 were as follows:
             
      Weighted  Remaining 
  Shares Under  Average  Contractual 
Exercise Prices Options  Exercise Price  Life in Years 
 
$20.02 – $30.74  1,305,563  $26.72   2.01 
$30.89 – $40.93  3,378,866   37.22   4.79 
$42.72 – $51.82  37,233   44.40   0.24 
$53.06 – $62.97  54,559   56.15   3.27 
$64.52 – $71.82  54,778   68.52   1.09 
$73.39 – $80.47  327,570   80.19   6.01 
$81.19 – $89.59  9,338   83.51   1.92 
          
Total  5,167,907  $37.96   4.07 
          
Performance Shares
Performance shares will be settled in cash and are accounted for as liability awards. Compensation expense (income) recognized for performance shares during the three months ended March 31, 2011 and 2010, net of amounts capitalized, totaled $1 million and $(3) million, respectively. No performance shares under the FirstEnergy LTIP were settled during the three months ended March 31, 2011 and 2010.
(B) ESOP
During 2011 shares of FirstEnergy common stock were purchased on the open market and contributed to participants’ accounts. Total ESOP-related compensation expense for the three months ended March 31, 2011 and 2010, net of amounts capitalized and dividends on common stock were $7 million and $5 million, respectively.
(C) EDCP
Compensation expense (income) recognized on EDCP stock units, for the three months ended March 31, 2011 and 2010, net of amounts capitalized, was not material.
(D) DCPD
DCPD expenses recognized for the three months ended March 31, 2011 and 2010 were approximately $1 million and $1 million. The net liability recognized for DCPD of approximately $5 million as of March 31, 2011 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, 1,076,779 stock units were available for future awards as of March 31, 2011.
12. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
In 2010,During the FASB amendedthree months ended March 31, 2011, there were no new accounting standards or interpretations issued, but not effective that would materially affect FirstEnergy’s financial statements.
13. SEGMENT INFORMATION
With the Receivable Topiccompletion of the FASB Accounting Standards CodificationAllegheny merger in the first quarter of 2011, FirstEnergy reorganized its management structure, which resulted in changes to enhance disclosures aboutits operating segments to be consistent with the credit quality of financing receivablesmanner in which management views the business. The new structure supports the combined company’s primary operations — distribution, transmission, generation and the allowance for credit losses. The update amends existing disclosures to require an entity to provide a greater level of disaggregated information about the credit qualitymarketing and sale of its financing receivablesproducts. The external segment reporting is consistent with the internal financial reporting utilized by FirstEnergy’s chief executive officer (its chief operating decision maker) to regularly assess the performance of the business and its allowanceallocate resources. FirstEnergy now has three reportable operating segments — Regulated Distribution, Regulated Independent Transmission and Competitive Energy Services.

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Prior to the change in composition of business segments, FirstEnergy’s business was comprised of two reportable operating segments. The Energy Delivery Services segment included 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” segment consisted of corporate items and other businesses that were below the quantifiable threshold for credit losses. separate disclosure. Disclosures for FirstEnergy’s operating segments for 2010 have been reclassified to conform to the current presentation.
The amendment also requireschanges in FirstEnergy’s reportable segments during the first quarter of 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 Allegheny, 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 Company and FirstEnergy’s interest in PATH; TrAIL and PATH were acquired as part of the merger with Allegheny. The transmission assets and operations of JCP&L, Met-Ed, Penelec, MP, PE and WP remain within the Regulated Distribution segment.
AE Supply, an entity to disclose credit quality indicators, past due information, and modificationsoperator of its financing receivables. The amendment is effective for interim and annual reporting periods ending on or after December 15, 2010. FirstEnergy is currently evaluatinggeneration facilities that was acquired as part of the impact of adopting this standard on its financial statements.merger with Allegheny, was placed into the Competitive Energy Services segment.
12. SEGMENT INFORMATION
Financial information for each of FirstEnergy’s reportable segments is presented in the following table.table below, which includes financial results for Allegheny beginning February 25, 2011. FES and the Utilities do not have separate reportable operating segments. With the completion of transition to a fully competitive generation market in Ohio in the fourth quarter of 2009, the former Ohio Transitional Generation Services segment was combined with the Energy Delivery Services segment, consistent with how management views the business. Disclosures for FirstEnergy’s operating segments for 2009 have been reclassified to conform to the current presentation.
The Energy Delivery ServicesRegulated Distribution segment transmits and distributes electricity through FirstEnergy’s eightten utility operating companies, serving 4.5approximately 6 million customers within 36,10067,000 square miles of Ohio, Pennsylvania, West Virginia, Virginia, Maryland, New Jersey and New Jersey,York, and purchases power for its POLR and default service requirements in Ohio, Pennsylvania and New Jersey. ItsThis 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 (default(POLR or default service) in its Ohio, Pennsylvania andMaryland, 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 the formula rate recovery of costs and a return on debt and equity for capital expenditures in connection with TrAIL, PATH and other projects and revenues from providing transmission services to electric energy providers, power marketers and receiving transmission-related revenues from operation of a portion of the FirstEnergy transmission system. Its results reflect the net PJM and MISO transmission expenses related to the delivery of the respective generation loads andloads. On June 1, 2011, the deferral and amortizationATSI transmission assets currently dedicated to MISO are scheduled to be integrated into the PJM market. This integration brings all of certain fuel costs.FirstEnergy’s assets into one RTO.
The Competitive Energy Services segment, through FES, 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 POLR and default service requirements of FirstEnergy’s Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Maryland, Michigan and New Jersey. 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.
The Competitive Energy Services segment also includes Allegheny’s unregulated electric generation operations, including AE Supply and AE Supply’s interest in AGC. AE Supply owns, operates and controls the electric generation capacity of its 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 business segment controls approximately 14,000 MW20,000 MWs of capacity and also purchases electricity to meet sales obligations. The segment’s net income is primarily derived from affiliated and non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO to deliver energy to the segment’s customers.

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The otherOther segment contains corporate items and other businesses that are below the quantifiable threshold for separate disclosure as a reportable segment.

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Segment Financial Information
                                            
 Energy Competitive      Competitive Regulated       
 Delivery Energy Reconciling    Regulated Energy Independent Other/ Reconciling   
Three Months Ended Services Services Other Adjustments Consolidated  Distribution Services Transmission Corporate Adjustments Consolidated 
 (In millions)  (In millions) 
September 30, 2010
 
March 31, 2011
 
External revenues $2,757 $957 $11 $(32) $3,693  $2,268 $1,254 $67 $(23) $(22) $3,544 
Internal revenues 60 599 —  (659) —  — 343 — —  (311) 32 
                        
Total revenues 2,817 1,556 11  (691) 3,693  2,268 1,597 67  (23)  (333) 3,576 
Depreciation and amortization 287 62 6 3 358  245 88 13 6 — 352 
Investment income (loss), net 23 28 —  (5) 46  25 6 — —  (10) 21 
Net interest charges 123 30 2 12 167  131 68 9 19  (14) 213 
Income taxes 137  (17) 5  (6) 119  56 3 7  (20) 32 78 
Net income (loss) 224  (27) —  (22) 175  96 5 13  (35)  (34) 45 
Total assets 22,773 11,076 604 254 34,707  27,165 17,308 2,479 914 — 47,866 
Total goodwill 5,551 24 — — 5,575  5,551 976 — — — 6,527 
Property additions 208 255 8  (1) 470  177 214 27 31 — 449 
 ��  
September 30, 2009
 
March 31, 2010
 
External revenues $2,942 490 6  (30) 3,408  $2,484 $719 $57 $(22) $(6) $3,232 
Internal revenues — 617 —  (617) —  — 674 — —  (607) 67 
           
Total revenues 2,942 1,107 6  (647) 3,408 
Depreciation and amortization 373 69 3 4 449 
Investment income (loss), net 46 159 —  (14) 191 
Net interest charges 115 28 2 175 320 
Income taxes 99 121  (19)  (73) 128 
Net income 148 183 17  (118) 230 
Total assets 23,023 10,691 674 286 34,674 
Total goodwill 5,551 24 — — 5,575 
Property additions 182 224 14 12 432 
 
Nine Months Ended 
 
September 30, 2010
 
External revenues $7,673 2,453 21  (92) 10,055 
Internal revenues* 79 1,812 —  (1,824) 67 
                        
Total revenues 7,752 4,265 21  (1,916) 10,122  2,484 1,393 57  (22)  (613) 3,299 
Depreciation and amortization 888 194 25 7 1,114  313 77 12 3 — 405 
Investment income (loss), net 75 42 —  (24) 93  26 1 — 1  (12) 16 
Net interest charges 369 94 4 39 506  124 33 5 13  (3) 172 
Income taxes 295 106  (14)  (23) 364  62 42 7  (12) 12 111 
Net income (loss) 481 174  (3)  (72) 580  103 69 12  (19)  (16) 149 
Total assets 22,773 11,076 604 254 34,707  21,535 10,950 995 598 — 34,078 
Total goodwill 5,551 24 — — 5,575  5,551 24 — — — 5,575 
Property additions 546 860 18 43 1,467  152 329 14 13 — 508 
 
September 30, 2009
 
External revenues $8,755 1,329 18  (89) 10,013 
Internal revenues — 2,349 —  (2,349) — 
           
Total revenues 8,755 3,678 18  (2,438) 10,013 
Depreciation and amortization 1,098 201 7 11 1,317 
Investment income (loss), net 111 136 —  (40) 207 
Net interest charges 338 64 5 252 659 
Income taxes 190 409  (56)  (113) 430 
Net income 285 614 52  (197) 754 
Total assets 23,023 10,691 674 286 34,674 
Total goodwill 5,551 24 — — 5,575 
Property additions 524 893 133 25 1,575 
*Under the accounting standard for the effects of certain types of regulation, internal revenues are not fully offset for sales of RECs by FES to the Ohio Companies that are retained in inventory.
Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting primarily consist of interest expense related to holding company debt, corporate support services revenues and expenses and elimination of intersegment transactions.
14. IMPAIRMENT OF LONG-LIVED ASSETS
FirstEnergy reviews long-lived 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 for the amount by which the carrying value of the long-lived asset exceeds its estimated fair value. Two events occurred during the first quarter of 2011 that indicated the carrying value of certain assets may not be recoverable as described in the sections below.
Fremont Energy Center
On March 11, 2011, FirstEnergy and American Municipal Power, Inc., (AMP) entered into an agreement for the sale of 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. The agreement provides, among other things, for a targeted closing date in July 2011. The execution of this agreement triggered a need to evaluate the recoverability of the carrying value of the assets associated with the Fremont Energy Center. The estimated fair value of the Fremont Energy Center was based on the purchase price outlined in the sale agreement with American Municipal Power, Inc. The result of this evaluation indicated that the carrying cost of the Fremont Energy Center was not fully recoverable. As a result of the recoverability evaluation, FirstEnergy recorded an impairment charge of $11 million to operating income during the quarter ended March 31, 2011. On April 19, 2011, FGCO filed an section 203 application with the FERC for authorization to sell the Fremont Energy Center, including related capacity supply obligations, to AMP. Comments are due on the filing on or before May 10, 2011. FGCO requested FERC action by June 17, 2011.

 

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Peaking Facilities
During the three months ended March 31, 2011, FirstEnergy assessed the carrying values of certain peaking facilities that will more likely than not be sold or disposed of before the end of their useful lives. The estimated fair values were based on estimated sales prices quoted in an active market. The result of this evaluation indicated that the carrying costs of the peaking facilities were not fully recoverable. As a result of the recoverability evaluation, FirstEnergy recorded an impairment charge of $14 million to the operating income of its Competitive Energy Services segment during the quarter ended March 31, 2011.
13.15. ASSET RETIREMENT OBLIGATIONS
FirstEnergy has recognized applicable legal obligations for AROs and their associated cost for nuclear power plant decommissioning, reclamation of sludge disposal ponds and closure of coal ash disposal sites. In addition, FirstEnergy has recognized conditional asset retirement obligations (primarily for asbestos remediation).
The ARO liabilities for FES and OE include the decommissioning of the Perry nuclear generating facilities. FES and OE use an expected cash flow approach to measure the fair value of their nuclear decommissioning AROs.
During the first quarter of 2011, studies were completed to update the estimated cost of decommissioning the Perry nuclear generating facility. The cost studies resulted in a revision to the estimated cash flows associated with the ARO liabilities of FES and OE and reduced the liability for each subsidiary in the amounts of $40 million and $6 million, respectively, as of March 31, 2011.
The revision to the estimated cash flows had no significant impact on accretion of the obligation during the first quarter of 2011 when compared to the first quarter of 2010.
16. SUPPLEMENTAL GUARANTOR INFORMATION
On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has fully, unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES’ lease guaranty. This transaction is classified as an operating lease under GAAP for FES and FirstEnergy and as a financing for FGCO.
The condensed consolidating statements of income for the three month and nine month periods ended September 30,March 31, 2011 and 2010, and 2009, consolidating balance sheets as of September 30, 2010March 31, 2011 and December 31, 20092010 and consolidating statements of cash flows for the ninethree months ended September 30,March 31, 2011 and 2010 and 2009 for FES (parent and guarantor), FGCO and NGC (non-guarantor) are presented below. Investments in wholly owned subsidiaries are accounted for by FES using the equity method. Results of operations for FGCO and NGC are, therefore, reflected in FES’ investment accounts and earnings as if operating lease treatment was achieved. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and the entries required to reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction.

 

5371

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
                                        
For the Three Months Ended September 30, 2010 FES FGCO NGC Eliminations Consolidated 
For the Three Months Ended March 31, 2011 FES FGCO NGC Eliminations Consolidated 
 (In thousands)  (In thousands) 
 
REVENUES
 $1,540,885 $645,001 $380,542 $(1,012,751) $1,553,677  $1,366,899 $742,638 $467,967 $(1,186,416) $1,391,088 
                      
  
EXPENSES:
  
Fuel 13,403 329,009 48,675 — 391,087  1,203 293,862 48,044 — 343,109 
Purchased power from affiliates 1,058,965 13,404 56,763  (1,012,751) 116,381  1,184,606 1,772 68,743  (1,186,378) 68,743 
Purchased power from non-affiliates 411,084 — — — 411,084  296,733 205 — — 296,938 
Other operating expenses 84,169 97,322 116,112 12,190 309,793  177,529 118,245 188,009 12,152 495,935 
Provision for depreciation 752 23,845 36,005  (1,304) 59,298  879 31,539 37,333  (1,299) 68,452 
General taxes 6,216 8,875 6,713 — 21,804  12,263 9,453 7,389 — 29,105 
Impairment of long-lived assets — 291,934 — — 291,934  — 13,800 — — 13,800 
                      
Total expenses 1,574,589 764,389 264,268  (1,001,865) 1,601,381  1,673,213 468,876 349,518  (1,175,525) 1,316,082 
                      
  
OPERATING INCOME (LOSS)
  (33,704)  (119,388) 116,274  (10,886)  (47,704)  (306,314) 273,762 118,449  (10,891) 75,006 
                      
  
OTHER INCOME (EXPENSE):
  
Investment income 256 396 29,243 — 29,895  676 232 4,953 — 5,861 
Miscellaneous income (expense), including net income from equity investees 5,707 2,562 49  (3,553) 4,765 
Miscellaneous income, including net income from equity investees 247,859 584 —  (229,202) 19,241 
Interest expense — affiliates  (60)  (2,021)  (416) —  (2,497)  (50)  (451)  (516) —  (1,017)
Interest expense — other  (24,158)  (26,243)  (15,028) 15,885  (49,544)  (24,133)  (27,758)  (16,836) 15,767  (52,960)
Capitalized interest 95 19,024 3,836 — 22,955  131 4,826 4,962 — 9,919 
                      
Total other income (expense)  (18,160)  (6,282) 17,684 12,332 5,574  224,483  (22,567)  (7,437)  (213,435)  (18,956)
                      
  
INCOME BEFORE INCOME TAXES
  (51,864)  (125,670) 133,958 1,446  (42,130)
INCOME (LOSS) BEFORE INCOME TAXES
  (81,831) 251,195 111,012  (224,326) 56,050 
  
INCOME TAXES (BENEFITS)
  (15,138)  (44,364) 51,600 2,498  (5,404)  (117,841) 93,129 42,374 2,454 20,116 
                      
  
NET INCOME (LOSS)
 $(36,726) $(81,306) $82,358 $(1,052) $(36,726)
NET INCOME
 36,010 158,066 68,638  (226,780) 35,934 
            
Loss attributable to noncontrolling interest —  (76) — —  (76)
           
 
EARNINGS AVAILABLE TO PARENT
 $36,010 $158,142 $68,638 $(226,780) $36,010 
           

 

5472

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
                                        
For the Nine Months Ended September 30, 2010 FES FGCO NGC Eliminations Consolidated 
For the Three Months Ended March 31, 2010 FES FGCO NGC Eliminations Consolidated 
 (In thousands)  (In thousands) 
  
REVENUES
 $4,203,610 $1,793,986 $1,145,795 $(2,886,947) $4,256,444  $1,367,025 $568,364 $426,320 $(973,616) $1,388,093 
                      
  
EXPENSES:
  
Fuel 25,768 910,739 125,212 — 1,061,719  5,097 280,863 42,261 — 328,221 
Purchased power from affiliates 2,940,360 25,646 167,173  (2,886,947) 246,232  968,537 5,079 60,953  (973,616) 60,953 
Purchased power from non-affiliates 1,160,119 — — — 1,160,119  450,216 — — — 450,216 
Other operating expenses 218,278 289,638 371,882 36,568 916,366  53,125 99,776 139,420 12,189 304,510 
Provision for depreciation 2,253 77,838 109,364  (3,920) 185,535  790 26,527 36,910  (1,309) 62,918 
General taxes 17,432 32,702 20,688 — 70,822  5,498 14,600 6,648 — 26,746 
Impairment charges of long-lived assets — 293,767 — — 293,767 
Impairment of long-lived assets — 1,833 — — 1,833 
                      
Total expenses 4,364,210 1,630,330 794,319  (2,854,299) 3,934,560  1,483,263 428,678 286,192  (962,736) 1,235,397 
                      
  
OPERATING INCOME (LOSS)
  (160,600) 163,656 351,476  (32,648) 321,884   (116,238) 139,686 140,128  (10,880) 152,696 
                      
  
OTHER INCOME (EXPENSE):
  
Investment income 3,964 531 39,483 — 43,978 
Investment income (loss) 1,897 54  (1,234) — 717 
Miscellaneous income (expense), including net income from equity investees 323,371 1,638 50  (314,591) 10,468  166,373 200  (101)  (163,329) 3,143 
Interest expense — affiliates  (179)  (5,917)  (1,266) —  (7,362)  (58)  (1,812)  (435) —  (2,305)
Interest expense — other  (71,793)  (80,548)  (46,152) 47,933  (150,560)  (23,373)  (26,506)  (15,763) 15,998  (49,644)
Capitalized interest 293 54,930 11,327 — 66,550  100 16,333 3,257 — 19,690 
                      
Total other income (expense) 255,656  (29,366) 3,442  (266,658)  (36,926) 144,939  (11,731)  (14,276)  (147,331)  (28,399)
                      
  
INCOME BEFORE INCOME TAXES
 95,056 134,290 354,918  (299,306) 284,958  28,701 127,955 125,852  (158,211) 124,297 
  
INCOME TAXES (BENEFITS)
  (82,069) 52,144 130,163 7,595 107,833   (51,225) 48,043 45,013 2,540 44,371 
                      
  
NET INCOME
 $177,125 $82,146 $224,755 $(306,901) $177,125  $79,926 $79,912 $80,839 $(160,751) $79,926 
                      

 

55

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

56

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

5773

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)
                               
As of September 30, 2010 FES FGCO NGC Eliminations Consolidated 
As of March 31, 2011 FES FGCO NGC Eliminations Consolidated 
 (In thousands)  (In thousands) 
ASSETS
  
 
CURRENT ASSETS:
  
Cash and cash equivalents $— $1 $9 $— $10  $— $6,831 $8 $— $6,839 
Receivables-  
Customers 325,265 — — — 325,265  388,951 — — — 388,951 
Associated companies 299,222 193,951 112,523  (335,710) 269,986  621,241 500,097 269,750  (857,808) 533,280 
Other 34,052 4,831 18,524 — 57,407  27,966 7,617 51,128 — 86,711 
Notes receivable from associated companies 10,100 329,461 162,087 — 501,648  5,742 389,312 83,364 — 478,418 
Materials and supplies, at average cost 28,411 301,761 223,871 — 554,043  46,747 251,190 191,060 — 488,997 
Derivatives 328,156 — — — 328,156 
Prepayments and other 191,423 9,669 2,973 — 204,065  41,403 9,093 948  (506) 50,938 
                      
 888,473 839,674 519,987  (335,710) 1,912,424  1,460,206 1,164,140 596,258  (858,314) 2,362,290 
                      
  
PROPERTY, PLANT AND EQUIPMENT:
  
In service 94,787 4,640,027 5,313,456  (385,006) 9,663,264  99,899 6,102,623 5,421,719  (384,676) 11,239,565 
Less — Accumulated provision for depreciation 16,209 2,173,661 2,098,927  (174,416) 4,114,381  17,918 2,035,726 2,230,588  (176,690) 4,107,542 
                      
 78,578 2,466,366 3,214,529  (210,590) 5,548,883  81,981 4,066,897 3,191,131  (207,986) 7,132,023 
Construction work in progress 7,523 2,221,270 507,842 — 2,736,635  8,139 147,546 600,620 — 756,305 
Property, plant and equipment held for sale, net — 476,602 — — 476,602 
                      
 86,101 4,687,636 3,722,371  (210,590) 8,285,518  90,120 4,691,045 3,791,751  (207,986) 8,364,930 
                      
  
INVESTMENTS:
  
Nuclear plant decommissioning trusts — — 1,158,376 — 1,158,376  — — 1,159,903 — 1,159,903 
Investment in associated companies 4,825,221 — —  (4,825,221) —  5,175,787 — —  (5,175,787) — 
Other 560 6,639 201 — 7,400  371 9,171 202 — 9,744 
                      
 4,825,781 6,639 1,158,577  (4,825,221) 1,165,776  5,176,158 9,171 1,160,105  (5,175,787) 1,169,647 
                      
  
DEFERRED CHARGES AND OTHER ASSETS:
  
Accumulated deferred income taxes 71,165 402,397 —  (470,205) 3,357 
Accumulated deferred income tax benefits 32,544 376,182 —  (408,726) — 
Customer intangibles 127,420 — — — 127,420  131,870 — — — 131,870 
Goodwill 24,248 — — — 24,248  24,248 — — — 24,248 
Property taxes — 27,811 22,314 — 50,125  — 16,463 24,649 — 41,112 
Unamortized sale and leaseback costs — — — 61,934 61,934  — 23,288 — 67,515 90,803 
Derivatives 211,223 — — — 211,223 
Other 142,039 75,033 7,842  (60,582) 164,332  26,661 75,647 8,157  (57,408) 53,057 
                      
 364,872 505,241 30,156  (468,853) 431,416  426,546 491,580 32,806  (398,619) 552,313 
                      
 $6,165,227 $6,039,190 $5,431,091 $(5,840,374) $11,795,134  $7,153,030 $6,355,936 $5,580,920 $(6,640,706) $12,449,180 
                      
  
LIABILITIES AND CAPITALIZATION
  
  
CURRENT LIABILITIES:
  
Currently payable long-term debt $765 $487,357 $927,772 $(19,102) $1,396,792  $785 $373,550 $632,106 $(19,578) $986,863 
Short-term borrowings-  
Associated companies — 9,642 — — 9,642  321,133 39,410 — — 360,543 
Other 100,000 — — — 100,000  — 661 — — 661 
Accounts payable-  
Associated companies 305,726 244,383 227,328  (305,419) 472,018  769,133 290,902 208,889  (768,988) 499,936 
Other 95,287 109,641 — — 204,928  92,874 96,270 — — 189,144 
Accrued taxes 1,821 46,889 56,535  (45,823) 59,422  2,721 98,597 65,919  (100,744) 66,493 
Derivatives 380,744 — — — 380,744 
Other 253,368 110,964 28,383 38,109 430,824  31,698 119,402 26,282 47,143 224,525 
                      
 756,967 1,008,876 1,240,018  (332,235) 2,673,626  1,599,088 1,018,792 933,196  (842,167) 2,708,909 
                      
  
CAPITALIZATION:
  
Common stockholder’s equity 3,730,964 2,443,222 2,362,711  (4,805,933) 3,730,964  3,824,540 2,673,372 2,487,105  (5,160,461) 3,824,556 
Long-term debt and other long-term obligations 1,518,779 2,053,532 506,533  (1,259,694) 2,819,150  1,488,455 2,113,043 793,250  (1,249,751) 3,144,997 
                      
 5,249,743 4,496,754 2,869,244  (6,065,627) 6,550,114  5,312,995 4,786,415 3,280,355  (6,410,212) 6,969,553 
                      
  
NONCURRENT LIABILITIES:
  
Deferred gain on sale and leaseback transaction — — — 967,583 967,583  — — — 950,726 950,726 
Accumulated deferred income taxes — — 410,095  (410,095) —  — — 456,556  (339,053) 117,503 
Accumulated deferred investment tax credits — 34,050 21,217 — 55,267  — 32,511 20,670 53,181 
Asset retirement obligations — 26,395 851,127 — 877,522  — 27,114 839,529 — 866,643 
Retirement benefits 36,528 192,251 — — 228,779  48,818 240,467 — — 289,285 
Property taxes — 27,811 22,314 — 50,125  — 16,463 24,649 — 41,112 
Lease market valuation liability — 228,119 — — 228,119  — 205,366 — — 205,366 
Derivatives 168,409 — — — 168,409 
Other 121,989 24,934 17,076 — 163,999  23,720 28,808 25,965 — 78,493 
                      
 158,517 533,560 1,321,829 557,488 2,571,394  240,947 550,729 1,367,369 611,673 2,770,718 
                      
 $6,165,227 $6,039,190 $5,431,091 $(5,840,374) $11,795,134  $7,153,030 $6,355,936 $5,580,920 $(6,640,706) $12,449,180 
                      

 

5874

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)
                               
As of December 31, 2009 FES FGCO NGC Eliminations Consolidated 
As of December 31, 2010 FES FGCO NGC Eliminations Consolidated 
 (In thousands)  (In thousands) 
ASSETS
  
 
CURRENT ASSETS:
  
Cash and cash equivalents $— $3 $9 $— $12  $— $9,273 $8 $— $9,281 
Receivables-  
Customers 195,107 — — — 195,107  365,758 — — — 365,758 
Associated companies 305,298 175,730 134,841  (297,308) 318,561  333,323 356,564 125,716  (338,038) 477,565 
Other 28,394 10,960 12,518 — 51,872  21,010 55,758 12,782 — 89,550 
Notes receivable from associated companies 416,404 240,836 147,863 — 805,103  34,331 188,796 173,643 — 396,770 
Materials and supplies, at average cost 17,265 307,079 215,197 — 539,541  40,713 276,149 228,480 — 545,342 
Derivatives 181,660 — — — 181,660 
Prepayments and other 80,025 18,356 9,401 — 107,782  47,712 11,352 1,107 — 60,171 
                      
 1,042,493 752,964 519,829  (297,308) 2,017,978  1,024,507 897,892 541,736  (338,038) 2,126,097 
                      
  
PROPERTY, PLANT AND EQUIPMENT:
  
In service 90,474 5,478,346 5,174,835  (386,023) 10,357,632  96,371 6,197,776 5,411,852  (384,681) 11,321,318 
Less — Accumulated provision for depreciation 13,649 2,778,320 1,910,701  (171,512) 4,531,158  17,039 2,020,463 2,162,173  (175,395) 4,024,280 
                      
 76,825 2,700,026 3,264,134  (214,511) 5,826,474  79,332 4,177,313 3,249,679  (209,286) 7,297,038 
Construction work in progress 6,032 2,049,078 368,336 — 2,423,446  8,809 519,651 534,284 — 1,062,744 
                      
 82,857 4,749,104 3,632,470  (214,511) 8,249,920  88,141 4,696,964 3,783,963  (209,286) 8,359,782 
                      
  
INVESTMENTS:
  
Nuclear plant decommissioning trusts — — 1,088,641 — 1,088,641  — — 1,145,846 — 1,145,846 
Investment in associated companies 4,477,602 — —  (4,477,602) —  4,941,763 — —  (4,941,763) — 
Other 1,137 21,127 202 — 22,466  374 11,128 202 — 11,704 
                      
 4,478,739 21,127 1,088,843  (4,477,602) 1,111,107  4,942,137 11,128 1,146,048  (4,941,763) 1,157,550 
                      
  
DEFERRED CHARGES AND OTHER ASSETS:
  
Accumulated deferred income taxes 93,379 381,849 —  (388,602) 86,626 
Accumulated deferred income tax benefits 42,986 412,427 —  (455,413) — 
Customer intangibles 16,566 — — — 16,566  133,968 — — — 133,968 
Goodwill 24,248 — — — 24,248  24,248 — — — 24,248 
Property taxes — 27,811 22,314 — 50,125  — 16,463 24,649 — 41,112 
Unamortized sale and leaseback costs — 16,454 — 56,099 72,553  — 10,828 — 62,558 73,386 
Derivatives 97,603 — — — 97,603 
Other 82,845 71,179 18,755  (51,114) 121,665  21,018 70,810 14,463  (57,602) 48,689 
                      
 217,038 497,293 41,069  (383,617) 371,783  319,823 510,528 39,112  (450,457) 419,006 
                      
 $5,821,127 $6,020,488 $5,282,211 $(5,373,038) $11,750,788  $6,374,608 $6,116,512 $5,510,859 $(5,939,544) $12,062,435 
                      
  
LIABILITIES AND CAPITALIZATION
  
  
CURRENT LIABILITIES:
  
Currently payable long-term debt $736 $646,402 $922,429 $(18,640) $1,550,927  $100,775 $418,832 $632,106 $(19,578) $1,132,135 
Short-term borrowings-  
Associated companies — 9,237 — — 9,237  — 11,561 — — 11,561 
Other 100,000 — — — 100,000  — — — — — 
Accounts payable-  
Associated companies 261,788 170,446 295,045  (261,201) 466,078  351,172 212,620 249,820  (346,989) 466,623 
Other 51,722 193,641 — — 245,363  139,037 102,154 — — 241,191 
Accrued taxes 44,213 61,055 22,777  (44,887) 83,158  3,358 36,187 30,726  (142) 70,129 
Derivatives 266,411 — — — 266,411 
Other 173,015 132,314 16,734 36,994 359,057  51,619 147,754 15,156 37,142 251,671 
                      
 631,474 1,213,095 1,256,985  (287,734) 2,813,820  912,372 929,108 927,808  (329,567) 2,439,721 
                      
  
CAPITALIZATION:
  
Common stockholder’s equity 3,514,571 2,346,515 2,119,488  (4,466,003) 3,514,571  3,788,245 2,514,775 2,413,580  (4,928,859) 3,787,741 
Long-term debt and other long-term obligations 1,519,339 1,906,818 554,825  (1,269,330) 2,711,652  1,518,586 2,118,791 793,250  (1,249,752) 3,180,875 
                      
 5,033,910 4,253,333 2,674,313  (5,735,333) 6,226,223  5,306,831 4,633,566 3,206,830  (6,178,611) 6,968,616 
                      
  
NONCURRENT LIABILITIES:
  
Deferred gain on sale and leaseback transaction — — — 992,869 992,869  — — — 959,154 959,154 
Accumulated deferred income taxes — — 342,840  (342,840) —  — — 448,115  (390,520) 57,595 
Accumulated deferred investment tax credits — 36,359 22,037 — 58,396  — 33,280 20,944 — 54,224 
Asset retirement obligations — 25,714 895,734 — 921,448  — 26,780 865,271 — 892,051 
Retirement benefits 33,144 170,891 — — 204,035  48,214 236,946 — — 285,160 
Property taxes — 27,811 22,314 — 50,125  — 16,463 24,649 — 41,112 
Lease market valuation liability — 262,200 — — 262,200  — 216,695 — — 216,695 
Derivatives 81,393 — — — 81,393 
Other 122,599 31,085 67,988 — 221,672  25,798 23,674 17,242 — 66,714 
                      
 155,743 554,060 1,350,913 650,029 2,710,745  155,405 553,838 1,376,221 568,634 2,654,098 
                      
 $5,821,127 $6,020,488 $5,282,211 $(5,373,038) $11,750,788  $6,374,608 $6,116,512 $5,510,859 $(5,939,544) $12,062,435 
                      

 

5975

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
                               
For the Nine Months Ended September 30, 2010 FES FGCO NGC Eliminations Consolidated 
For the Three Months Ended March 31, 2011 FES FGCO NGC Eliminations Consolidated 
 (In thousands)  (In thousands) 
  
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES
 $(289,503) $402,332 $520,272 $(9,174) $623,927  $(215,124) $267,047 $41,702 $— $93,625 
                      
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New Financing-  
Long-term debt — 249,520 — — 249,520  — 90,190 60,000 — 150,190 
Short-term borrowings, net — 405 — — 405  321,134 28,509 — — 349,643 
Redemptions and Repayments-  
Long-term debt  (599)  (261,965)  (42,949) 9,174  (296,339)  (130,208)  (141,220)  (60,000) —  (331,428)
Other  (459)  (237)  (102) —  (798)  (430)  (222)  (365) —  (1,017)
                      
Net cash used for financing activities  (1,058)  (12,277)  (43,051) 9,174  (47,212)
Net cash provided from (used for) financing activities 190,496  (22,743)  (365) — 167,388 
                      
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (5,497)  (417,146)  (378,595) —  (801,238)  (2,858)  (39,791)  (116,357) —  (159,006)
Proceeds from asset sales — 117,213 — — 117,213 
Sales of investment securities held in trusts — — 1,478,086 — 1,478,086  — — 215,620 — 215,620 
Purchases of investment securities held in trusts — —  (1,511,273) —  (1,511,273) — —  (230,912) —  (230,912)
Loans from (to) associated companies, net 406,304  (88,625)  (14,224) — 303,455  28,589  (200,516) 90,280 —  (81,647)
Customer acquisition costs  (110,073) — — —  (110,073)  (1,103) — — —  (1,103)
Leasehold improvement payments to associated companies — —  (51,204) —  (51,204)
Other  (173)  (1,499)  (11) —  (1,683) —  (6,439) 32 —  (6,407)
                      
Net cash provided from (used for) investing activities 290,561  (390,057)  (477,221) —  (576,717) 24,628  (246,746)  (41,337) —  (263,455)
                      
  
Net change in cash and cash equivalents —  (2) — —  (2) —  (2,442) — —  (2,442)
Cash and cash equivalents at beginning of period — 3 9 — 12  — 9,273 8 — 9,281 
                      
Cash and cash equivalents at end of period $— $1 $9 $— $10  $— $6,831 $8 $— $6,839 
                      

 

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FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
                     
For the Nine Months Ended September 30, 2009 FES  FGCO  NGC  Eliminations  Consolidated 
  (In thousands) 
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES
 $(37,990) $520,169  $408,364  $(8,732) $881,811 
                
                     
CASH FLOWS FROM FINANCING ACTIVITIES:
                    
New Financing-                    
Long-term debt  1,498,087   524,710   333,965   —   2,356,762 
Short-term borrowings, net  —   —   —   —   — 
Equity contributions from parent  —   100,000   150,000   (250,000)  — 
Redemptions and Repayments-                    
Long-term debt  (1,507)  (258,583)  (366,857)  8,734   (618,213)
Short-term borrowings, net  (901,119)  (257,357)  (6,347)  —   (1,164,823)
Other  (11,583)  (5,261)  (3,160)  (2)  (20,006)
                
Net cash provided from financing activities  583,878   103,509   107,601   (241,268)  553,720 
                
                     
CASH FLOWS FROM INVESTING ACTIVITIES:
                    
Property additions  (2,224)  (439,531)  (400,845)  —   (842,600)
Proceeds from asset sales  —   16,129   —   —   16,129 
Sales of investment securities held in trusts  —   —   2,152,717   —   2,152,717 
Purchases of investment securities held in trusts  —   —   (2,175,135)  —   (2,175,135)
Loans to associated companies, net  (27,054)  (178,746)  (93,041)  —   (298,841)
Investment in subsidiary  (250,000)  —   —   250,000   — 
Other  249   (21,470)  339   —   (20,882)
                
Net cash used for investing activities  (279,029)  (623,618)  (515,965)  250,000   (1,168,612)
                
                     
Net change in cash and cash equivalents  266,859   60   —   —   266,919 
Cash and cash equivalents at beginning of period  —   39   —   —   39 
                
Cash and cash equivalents at end of period $266,859  $99  $—  $—  $266,958 
                
14. INTANGIBLE ASSETS
FES has acquired certain customer contract rights, which were capitalized as intangible assets. These rights allow FES to supply electric generation needs to customers, and the recorded value is being amortized ratably over the term of the related contracts. Net intangible assets of $127 million are included in other assets on FirstEnergy’s Consolidated Balance Sheet as of September 30, 2010.
For the three and nine months ended September 30, 2010, amortization expense was approximately $2 million and $6 million, respectively.
15. IMPAIRMENT OF LONG-LIVED ASSETS
FirstEnergy reviews long-lived 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, 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.
During the quarter ending September 30, 2010, FirstEnergy announced its intention to make operational changes at certain coal-fired FGCO units. The announcement of the operational change indicated a need to evaluate the future recoverability of the carrying value of the assets associated with the affected FGCO units. As a result of the recoverability evaluation, FirstEnergy recorded an impairment of $292 million to other operating expense within continuing operations of its competitive energy services segment for the quarter ending September 30, 2010. This impairment represents a $285 million write down of the carrying value of the assets associated with the affected FGCO units to their estimated fair value and a charge of $7 million for excessive or obsolete inventory identified as a result of the operational changes.
                     
For the Three Months Ended March 31, 2010 FES  FGCO  NGC  Eliminations  Consolidated 
  (In thousands) 
                     
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES
 $(147,718) $40,130  $98,692  $—  $(8,896)
                
                     
CASH FLOWS FROM FINANCING ACTIVITIES:
                    
Redemptions and Repayments-                    
Long-term debt  (197)  (1,081)  —   —   (1,278)
Short-term borrowings, net  —   (9,237)  —   —   (9,237)
Other  (453)  (177)  (101)  —   (731)
                
Net cash used for financing activities  (650)  (10,495)  (101)  —   (11,246)
                
                     
CASH FLOWS FROM INVESTING ACTIVITIES:
                    
Property additions  (2,103)  (174,163)  (125,337)  —   (301,603)
Proceeds from asset sales  —   114,272   —   —   114,272 
Sales of investment securities held in trusts  —   —   272,094   —   272,094 
Purchases of investment securities held in trusts  —   —   (284,888)  —   (284,888)
Loans from associated companies, net  250,908   31,232   39,540   —   321,680 
Customer acquisition costs  (100,615)  —   —   —   (100,615)
Other  178   (977)  —   —   (799)
                
Net cash provided from (used for) investing activities  148,368   (29,636)  (98,591)  —   20,141 
                
                     
Net change in cash and cash equivalents  —   (1)  —   —   (1)
Cash and cash equivalents at beginning of period  —   3   9   —   12 
                
Cash and cash equivalents at end of period $—  $2  $9  $—  $11 
                

 

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FirstEnergy used various assumptions in evaluating whether the FGCO units’ carrying value was recoverable. The estimated undiscounted cash flows were based on assumptions about budgeted net operating income; the impact of current market conditions on future revenues including a long-term view of a continual depression of future market prices; decreased customer demand; and the estimated cost of remedial retro-fitting of the FGCO units to comply with proposed changes in federal environmental laws. The result of this evaluation indicated that the carrying costs of the FGCO units were not fully recoverable.
FirstEnergy further evaluated the extent to which the carrying value of the FGCO units exceeded their estimated fair value. FirstEnergy applied the income approach to estimating fair value under a discounted cash flow valuation technique to convert future cash flows expected over the remaining life of the asset group to a single present value. The assumptions used to estimate the non-recurring fair value measurement of the FGCO units applied significant unobservable inputs considered Level 3 under the fair value hierarchy. The estimated cash flows used during the recoverability test were discounted using the weighted average cost of capital for a market participant.
16. PROPOSED MERGER WITH ALLEGHENY ENERGY, INC.
As previously disclosed, on February 10, 2010, FirstEnergy entered into an Agreement and Plan of Merger, subsequently amended on June 4, 2010 (Merger Agreement), with Element Merger Sub, Inc., a Maryland corporation, its wholly-owned subsidiary (Merger Sub) and Allegheny Energy, Inc., a Maryland corporation (Allegheny Energy). Upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will merge with and into Allegheny Energy with Allegheny Energy 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 Energy common stock, including grants of restricted common stock, will automatically be converted into the right to receive 0.667 of a share of common stock of FirstEnergy, and Allegheny Energy stockholders will own approximately 27% of the combined company. Based on the closing stock prices for both companies on February 10, 2010, Allegheny Energy shareholders would receive a value of $27.65 per share. On July 15, 2010, the most recent practicable date prior to the effectiveness of the Form S-4 registration statement, the exchange ratio represented approximately $25.06 in value for each share of Allegheny Energy common stock. FirstEnergy will also assume all outstanding Allegheny Energy debt.
Pursuant to the Merger Agreement, completion of the merger is conditioned upon, among other things, shareholder approval of both companies, which was received on September 14, 2010; the SEC’s clearance of a registration statement registering the FirstEnergy common stock to be issued in connection with the merger, which occurred on July 16, 2010; expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and approval by the FERC, the MDPSC, the PPUC and the PSCWV. On September 9, 2010, the VSCC approved the merger. The Merger Agreement also contains certain termination rights for both FirstEnergy and Allegheny Energy, and further provides for the payment of fees and expenses upon termination under specified circumstances.
FirstEnergy and Allegheny Energy currently anticipate completing the merger in the first half of 2011. Although FirstEnergy and Allegheny Energy believe that they will receive the required authorizations, approvals and consents to complete the merger, there can be no assurance as to the timing of these authorizations, approvals and consents or as to FirstEnergy’s and Allegheny Energy’s ultimate ability to obtain such authorizations, consents or approvals (or any additional authorizations, approvals or consents which may otherwise become necessary) or that such authorizations, approvals or consents will be obtained on terms and subject to conditions satisfactory to Allegheny Energy and FirstEnergy. Further information concerning the proposed merger is included in the Registration Statement filed by FirstEnergy with the SEC in connection with the merger.
In connection with the proposed merger, FirstEnergy recorded approximately $14 million ($11 million after tax) of merger transaction costs in the third quarter and approximately $35 million ($26 million after tax) of merger transaction costs in the first nine months of 2010. These costs are expensed as incurred.

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Item 2.
Item 2. Management’s Discussion and Analysis of Registrant and Subsidiaries
FIRSTENERGY CORP.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
EXECUTIVE SUMMARY
Earnings available to FirstEnergy Corp. in the thirdfirst quarter of 20102011 were $179$50 million, or basic and diluted earnings of $0.59$0.15 per share of common stock, compared with $234$155 million, or basic and diluted earnings of $0.77$0.51 per share of common stock in the thirdfirst quarter of 2009. Results in2010. The principal reasons for the third quarter of 2010 were adversely affected by an impairment charge for certain coal-fired generation units. Earnings available to FirstEnergy in the first nine months of 2010 were $599 million or basic earnings of $1.97 ($1.96 diluted) per share of common stock, compared with $768 million, or basic earnings of $2.52 per share of common stock ($2.51 diluted) in the first nine months of 2009.decreases are summarized below.
         
  Three Months  Nine Months 
  Ended  Ended 
Change in Basic Earnings Per Share From Prior Year September 30  September 30 
 
Basic Earnings Per Share — 2009 $0.77  $2.52 
Non-core asset sales/impairments  (0.60)  (1.14)
Trust securities impairments  (0.04)  — 
Regulatory charges  (0.02)  0.45 
Derivative mark-to-market adjustment — 2010  (0.03)  (0.07)
Organizational restructuring — 2009  0.08   0.14 
Merger transaction costs — 2010  (0.04)  (0.09)
Litigation settlements  —   0.04 
Debt call premium — 2009  0.30   0.31 
Income tax resolution — 2009  —   (0.04)
Income tax charge from healthcare legislation — 2010  —   (0.04)
Revenues  0.56   0.72 
Fuel and purchased power  (0.09)  (0.50)
Transmission expense  (0.18)  (0.16)
Amortization of regulatory assets, net  0.17   0.06 
Investment income  (0.26)  (0.23)
Other expenses  (0.03)  — 
       
Basic Earnings Per Share — 2010 $0.59  $1.97 
       
     
Change in Basic Earnings Per Share From Prior Year 2011 
     
Basic earnings Per Share — First Quarter 2010 $0.51 
Non-core asset sales/impairments  (0.03)
Trust securities impairments  0.01 
Mark-to-market adjustments  0.09 
Income tax charge from healthcare legislation — 2010  0.04 
Regulatory charges — 2011  (0.04)
Regulatory charges — 2010  0.08 
Merger-related costs  (0.34)
Revenues  (0.26)
Fuel and purchased power  0.21 
Transmission expense  (0.07)
Amortization of regulatory assets, net  0.07 
Interest expense  0.03 
Merger accounting — commodity contracts  (0.04)
Allegheny earnings contribution*  0.13 
Additional shares issued  (0.06)
Other  (0.18)
    
Basic earnings Per Share — First Quarter 2011 $0.15 
    
*Excludes merger accounting — commodity contracts, regulatory charges, mark-to-market adjustments and merger-related costs that are shown separately.
Pending Merger
As previously disclosed, onOn February 10, 2010,25, 2011, the merger between FirstEnergy entered into anand Allegheny closed. Pursuant to the terms of the Agreement and Plan of Merger subsequently amended on June 4, 2010, (Merger Agreement), withbetween FirstEnergy, Element Merger Sub.Sub, Inc., a Maryland corporation itsand a wholly-owned subsidiary of FirstEnergy (Merger Sub), and Allegheny Energy, Inc., a Maryland corporation (Allegheny Energy). Upon the terms and subject to the conditions set forth in the Merger Agreement,AE, Merger Sub will mergemerged with and into Allegheny EnergyAE with Allegheny EnergyAE continuing as the surviving corporation and a wholly-owned subsidiary of FirstEnergy. Pursuant to the Merger Agreement, upon the closingAs part of the merger, each issued and outstanding share of Allegheny Energy common stock, including grants of restricted common stock, will automatically be converted into the right to receiveAE shareholders received 0.667 of a share of common stock of FirstEnergy, and Allegheny Energy stockholders will own approximately 27% of the combined company. Based on the closing stock prices for both companies on February 10, 2010, Allegheny Energy shareholders would receive a value of $27.65 per share. On July 15, 2010, the most recent practicable date prior to the effectiveness of the Form S-4 registration statement, the exchange ratio represented approximately $25.06 in value for each share of Allegheny Energy common stock. FirstEnergy will also assume all outstanding Allegheny Energy debt.
FirstEnergy shareholders and Allegheny Energy stockholders approved the various proposals related to the merger in separate special shareholder meetings on September 14, 2010. FirstEnergy shareholders approved the issuance of shares 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 approximately $82 million and $14 million of merger transaction costs during the first quarter of 2011 and 2010, respectively. FirstEnergy’s consolidated financial statements include Allegheny’s results of operations and financial position effective February 25, 2011. In addition, in the three months ended March 31, 2011, $75 million of pre-tax merger integration costs and the other transactions contemplated$24 million of charges from merger settlements approved by the Merger Agreement and approved the amendment of FirstEnergy’s amended articles of incorporationregulatory agencies have been recognized. Charges resulting from merger settlements are not expected to increase the number of authorized shares of FirstEnergy common stock. The total votes cast at the FirstEnergy special shareholder meeting represented approximately 80% of FirstEnergy’s outstanding shares of common stock, of which 97% votedbe material in favor of the proposals. Allegheny Energy stockholders approved the merger with total votes representing 80% of Allegheny Energy’s outstanding shares, of which 99% voted in favor of the merger.future periods.

 

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PursuantOperational Matters
Fremont Energy Center
On March 14, 2011, FirstEnergy entered into a definitive agreement to sell Fremont Energy Center (707 MW) to American Municipal Power, Inc. (AMP). Under the Merger Agreement, completionterms of the merger remains conditioned upon, among other things,agreement, AMP will purchase Fremont Energy Center for approximately $485 million, based on 685 MW of output. The purchase price would be incrementally increased, not to exceed an additional $16 million, to reflect additional output and transmission export capacity to its nameplate capacity of 707 MW. In addition, AMP would reimburse FirstEnergy up to $25.3 million for construction costs incurred from February 1, 2011 through the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and approval by FERC, the MDPSC, the PPUC and the PSCWV. The Merger Agreement also contains certain termination rights for both FirstEnergy and Allegheny Energy, and further provides for the payment of fees and expenses upon termination under specified circumstances.
FirstEnergy and Allegheny Energy currently anticipate completing the merger in the first half of 2011. Although FirstEnergy and Allegheny Energy believe that they will receive the remaining required authorizations, approvals and consents to complete the merger, there can be no assurance as to the timing of these authorizations, approvals and consents or as to FirstEnergy’s and Allegheny Energy’s ultimate ability to obtain such authorizations, consents or approvals (or any additional authorizations, approvals or consents which may otherwise become necessary) or that such authorizations, approvals or consents will be obtained on terms and subject to conditions satisfactory to Allegheny Energy and FirstEnergy. Further information concerning the proposed merger is included in the Registration Statement filed by FirstEnergy with the SEC in connection with the merger.
FirstEnergy incurred approximately $14 million ($11 million after tax) of merger transaction costs in the third quarter and approximately $35 million ($26 million after tax) of merger transaction costs in the first nine months of 2010. These costs are charged to expense as incurred.
FERC
closing date. On May 11, 2010, FirstEnergy and Allegheny EnergyApril 19, 2011, FGCO filed an application with the FERC for approval of their proposed merger. Underauthorization to sell the Federal Power Act, FERC has 180 daysFremont Energy Center, including related capacity supply obligations, to rule on a completed merger application. FirstEnergy and Allegheny Energy submitted additional information regarding the merger application on June 21, 2010 in response to a request by FERC. Interventions and protests were filed with FERC on July 12, 2010. On July 27, 2010, FirstEnergy filed additional information with FERC in response to the interventions. FERCAMP. The transaction is expected to complete its reviewclose in sufficient time to meet the anticipated merger closing schedule in the first half ofJuly 2011.
State Regulatory Merger FilingsPerry Refueling
FENOC shutdown the Perry Nuclear Plant on April 18, 2011, for scheduled refueling and maintenance. During the outage 284 of the 748 fuel assemblies will be exchanged and maintenance safety inspections will be conducted while the unit is off line. Preventative maintenance to ensure continued safe and reliable operations will be preformed, including replacing several control rod blades, rewinding the generator and testing more than 100 valves. On April 25, 2011, the NRC began a Special Inspection to review the circumstances surrounding work activities to remove a source range monitor from the reactor core on April 22, 2011.
Beaver Valley Refueling
On September 9, 2010,April 11, 2011, FENOC announced that Beaver Valley Unit 2 (911 MW) returned to service following a March 7, 2011 shutdown for refueling and maintenance. During the VSCC approved a petition foroutage 60 of the FirstEnergy-Allegheny Energy merger.157 fuel assemblies were exchanged, safety inspections were conducted, and numerous maintenance and improvement projects were completed.
Pennsylvania SettlementSeneca Plant Maintenance
In March 2011, FirstEnergy announced that the Seneca Pumped-Storage Hydroelectric facility (451 MW) will repave its Upper Reservoir, overhaul the shutoff valves and perform routine maintenance activities.
TrAIL
On October 25, 2010, FirstEnergyApril 15, 2011, the TrAIL 500 kV line segment from Meadowbrook substation to Loudoun substation in Virginia was successfully energized and Allegheny Energy filed a comprehensive settlement with the PPUC that addresses issues raised by 18 of the partiesis carrying load. The other segments are planned to the merger.be energized in May. The filing includes additional commitments relatedentire TrAIL line is scheduled to employment levels, including a five-year commitment to maintain at least 800 jobsbe completed and placed in Greensburg and Westmoreland County for the first year after the merger close, 675 jobs for the following 12 months, 650 jobs for the next year and 600 jobs for each of the next two years. The settlement also provides nearly $11 million over a three year time frame in distribution rate credits for West Penn Power customers, a distribution rate freeze for FirstEnergy’s current Pennsylvania utility customers and support for renewable and sustainable energy and customer choice. The settlement is subject to approval by the PPUC, and does not resolve issues raised by parties who did not join in the settlement.service no later than June 2011.
Hart-Scott-Rodino (HSR) Act FilingsSignal Peak
On May 25, 2010, FirstEnergy and AlleghenyMarch 16, 2011, Signal Peak Energy made HSR filings with the DOJ and Federal Trade Commission. On June 24, 2010, FirstEnergy and Allegheny Energy each received a request for additional informationletter from the DOJ. FirstEnergy and Allegheny Energy continue to cooperate with the DOJ and expect DOJ to completeMSHA indicating that its review in sufficient time to meet the anticipated merger closing schedule in the first halfmine is no longer being considered for a pattern of 2011.potential violations notice.
Financial Matters
Financing Activities
On August 20, 2010, FES completedMarch 16, 2011, Penelec and Met-Ed extended for three years the remarketing of $250 million of PCRBs. Of the $250 million, $235 millionLOCs supporting two series of PCRBs were converted fromcurrently outstanding in a variable interest rate to a fixed interest rate. The remaining $15 million of PCRBs continue to bear a fixed interest rate. The interest rate conversion minimizes financial risk by converting the long-term debt into a fixed rate and, as a result, reducing exposure to variable interest rates over the short-term. These remarketings included two series: $235 million of PCRBs that now bear a per-annum rate of 2.25% and are subject to mandatory purchase on June 3, 2013; and $15 million of PCRBs that now bear a per-annum rate of 1.5% and are subject to mandatory purchase on June 1, 2011.mode totaling $49 million.
On OctoberMarch 17 and April 1, 2010,2011, FES and Penelec completed the refinancing and remarketing of six series of PCRBs totaling $313$328 million. TheseEach of these series of PCRBs wereeither remained in or was converted fromto a variable interest rate mode supported by a three-year bank LOC. In connection with the remarketings, approximately $207 million aggregate principal amount of FMBs previously delivered to a fixed long term interest rateLOC providers were cancelled, and approximately $50 million aggregate principal amount of 3.375% per-annum andFMBs previously delivered to secure PCRBs are subjectexpected to mandatory purchasebe cancelled on July 1, 2015.May 31, 2011.
On October 22, 2010, Signal Peak and Global RailMarch 29, 2011, FES repaid a $100 million two-year term loan facility secured by FMBs that was scheduled to mature March 31, 2011. On April 8, 2011, FirstEnergy entered into a $350new $150 million syndicated two-year senior securedunsecured term loan facility among the two limited liability companies that comprise Signal Peak and Global Rail, as borrowers, Sovereign Bank, CoBank, Credit Agricole, U.S. Bank, BBVA Compass, Royal Bank of Canada, Fifth Third, Comerica Bank, CIBC Inc. and First Merit banks, as lenders, and Union Bank, N.A. as lender, administrative agent, collateral agent and syndication agent. FirstEnergy, together with WMB Loan Ventures LLC and WMB Loan Ventures II LLC, the entities that share ownership with FEV in the borrowers, have provided a guaranty of the borrowers’ obligations under the facility. The loan proceeds were used to repay $258 million of notes payable to FirstEnergy, including $9 million of interest and $63 million of bank loans that were scheduled to mature on November 16, 2010. Additional proceeds will be used for general company purposes, including an $11 million repayment of a third-party seller’s note maturing October 29, 2010.April 2013 maturity.

 

64

Operational Matters
Plant Operational Changes
On August 12, 2010, FGCO announced that it would be making operational changes to some of its smaller coal-fired units in response to the continued slow economy and lower demand for electricity and uncertainty related to proposed new federal environmental regulations. The units affected are Bay Shore units 2-4, Eastlake units 1-4, the Lake Shore Plant and the Ashtabula Plant, which together total 1,620 MW of capacity. During the period beginning September 2010 through August 2011 the affected units will operate with minimum three-day notice and in response to consumer demand. Beginning in September 2011, and continuing for approximately 18 months, the Bay Shore and Eastlake units (1,131 MW) will only be available during summer and winter months, and Ashtabula and Lake Shore will be temporarily idled (489 MW). As a result, the company recognized an impairment of $292 million for these assets. Together, these units have a generating capacity of 1,620MW, and in 2009 they produced approximately 6.8% of FGCO’s total generation output. The proposed changes are subject to review by MISO, PJM and the independent market monitors to ensure that there is no negative impact on system reliability.
Davis-Besse License Renewal
On August 30, 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse operating license. By a letter dated October 18, 2010, the NRC determined that the Davis-Besse license renewal application was complete and acceptable for docketing and further review. Davis-Besse currently is licensed until 2017; if approved, the renewal would extend operations for an additional 20 years, until 2037.
Fremont Energy Center Construction
During the third quarter, FGCO re-evaluated the schedule for completing the Fremont Plant (707 MW) due to current market conditions and the extension of the tax incentives included in the Small Business legislation through 2011. As a result, FGCO is extending the plant’s completion beyond 2010 to reduce overtime labor cost and outside contractor spend for the remainder of the project. We expect the extension of the completion schedule to add $33 million to the 2011 capital budget.
Regulatory Matters — General
DOE Smart Grid Grants and Smart Meter Implementation
On June 3, 2010, FirstEnergy received DOE’s grants totaling $57.4 million, awarded as part of the American Recovery and Reinvestment Act, to be used to introduce smart grid technologies in targeted areas of Pennsylvania, Ohio and New Jersey. The DOE grants represent 50% of the funding for the $114.9 million FE plans to invest in smart grid technologies. The PPUC and the NJBPU previously approved recovery for the applicable utilities portion of smart grid costs, and FirstEnergy has begun implementing smart grid programs in Pennsylvania and New Jersey. Implementation of the program in Ohio is underway following clarification by the PUCO in its entry on rehearing issued August 25, 2010 that the Ohio Companies are entitled to cost recovery for any costs not covered by the DOE grant.
Regulatory Matters — Ohio
New Ohio ESP
On August 25, 2010, the PUCO adopted a Combined Stipulation in the second ESP for the Ohio Companies’ effective June 1, 2011 through May 31, 2014. Under the new ESP, base distribution rates will remain unchanged during the term of the ESP, except in cases of emergencies, subject to riders and other changes provided in the Ohio Companies’ tariffs. Generation rates for each annual delivery period (June 1 to May 31) through May 31, 2014, will be determined through a CBP to be conducted every October and January for generation service.
The ESP provides for recovery of certain costs related to FirstEnergy’s integration into PJM, which is scheduled for June 1, 2011. However, the Ohio Companies will not seek recovery for any MISO exit fees, PJM integration costs, or legacy regional transmission expansion plan costs billed by PJM for the longer of a five year period from June 1, 2011 through May 31, 2016 or when the amount of costs avoided by customers for certain types of products totals $360 million dependent on the outcome of certain PJM proceedings for projects approved prior to June 1, 2011.
The new ESP also establishes a Delivery Capital Recovery Rider effective January 1, 2012, through May 31, 2014, which provides for recovery of property taxes, commercial activity tax and associated income taxes and for the opportunity to earn a return on and of plant in service associated with distribution, subtransmission and general and intangible plant that was not included in the Ohio Companies’ rate base as determined in the last distribution rate case. This rider is limited to expenditures through May 31, 2014, and recovery is capped at $150 million for 2012, $165 million for 2013 and $75 million for the first five months of 2014.
Ohio Generation Auction
On October 20, 2010, the Ohio Companies conducted a CBP to procure generation for customers who choose not to shop with an alternative supplier for delivery beginning June 1, 2011 through May 31, 2014. The auction consisted of one, two and three-year products. Fifty tranches in total were acquired through this auction. Seventeen tranches of the one-year product were acquired at a clearing price of $54.55 per MWh; seventeen tranches of the two-year product were acquired at a clearing price of $54.10 per MWh; and sixteen tranches of the three-year product were acquired at a clearing price of $56.58 per MWh. There were ten registered bidders that participated in the auction, with four bidders winning tranches in the auction. The auction consisted of twelve rounds. On October 22, 2010, the PUCO accepted the results of the auction. The next auction is scheduled for January 2011.

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Regulatory Matters — Pennsylvania
Met-EdOhio Energy Efficiency (EE) and Penelec Default ServicePeak Demand Reduction (DR) Portfolio Plan
On October 20, 2010,March 23, 2011, the PUCO approved the three-year EE and DR portfolio plan for the Ohio Companies. The Ohio Companies’ plan was developed to comply with the EE 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.
Penn SREC
On March 11, 2011, the PPUC approved the results of the finalPenn procurement of four auctions heldSRECs to procuremeet Pennsylvania’s Alternative Energy Portfolio Standards through 2020. One SREC represents the default service requirementssolar renewable energy attributes of one MWH of generation from a solar generating facility. Penn contracted for Met-Ed and Penelec customers who choose not19,800 SREC’s. This purchase of SRECs is equivalent to shopapproximately 2,200 MWH of solar power generation annually over the next nine years. The average cost is $199.09 per SREC, with an alternative supplier. For the five-month period of January 1,deliveries scheduled for June 2011 tothrough May 31, 2011, the tranche-weighted average prices ($/MWh) for Met-Ed’s residential and commercial classes were $67.10 and $68.28, respectively; Penelec’s tranche-weighted average prices were $55.76 and $58.24 for its residential and commercial classes, respectively. The October 2010 auction is the second of four auctions to procure commercial default service requirements for the 12-month period of June 1, 2011 to May 31, 2012 and residential requirements for the 24-month period of June 1, 2011 to May 31, 2013. For Met-Ed and Penelec commercial customers the tranche-weighted average price ($/MWh) was $63.97 and $54.33, respectively, and for residential customers the tranche-weighted average price was $66.66 and $55.74, respectively. In addition, the October 2010 auction procured supply for Met-Ed and Penelec industrial customers choosing the Fixed Price Service. For Met-Ed and Penelec, the average 12-month price ($/MWh) was $95.00 and $83.73, respectively. The remaining two auctions for these products will be conducted in January 2011 and March 2011.
On October 20, 2010, the PPUC also approved the default service RFP for the Residential Fixed Block On-Peak and Off-Peak energy products. For Penelec, the average price ($/MWh) for On-Peak and Off-Peak was $47.25 and $38.62, respectively. For Met-Ed, the average price ($/MWh) for On-Peak and Off-Peak was $55.07 and $40.81, respectively.
Regulatory Matters — FERC
MISO Multi-Value Project Rule Proposal
On September 10, 2010, FirstEnergy filed a protest to MISO’s MVP proposal. FirstEnergy believes that MISO’s proposal to allocate costs of MVP 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) among other objections. FirstEnergy also argued that, in light of progress to date in the ATSI move to PJM, it would be unjust and unreasonable to allocate any MVP costs to the ATSI zone, or to ATSI. FirstEnergy is unable to predict the outcome of this matter.
2020.
FIRSTENERGY’S BUSINESS
With the completion of the Allegheny 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 a diversified energy company headquarteredconsistent with the internal financial reporting utilized 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 Akron, Ohio, that operates primarily through two corecomposition of business segments, (see ResultsFirstEnergy’s business was comprised of Operations).
two reportable operating segments. The Energy Delivery Servicestransmits segment included 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” segment 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 the first quarter of 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 Allegheny, 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 Company and FirstEnergy’s interest in PATH; TrAIL and PATH were acquired as part of the merger with Allegheny. The transmission assets and operations of JCP&L, Met-Ed, Penelec, MP, PE and WP remain within the Regulated Distribution segment.
AE Supply, an operator of generation facilities that was acquired as part of the merger with Allegheny, was placed into the Competitive Energy Services segment.
Financial information for each of FirstEnergy’s reportable segments is presented in the table below, which includes financial results for the Allegheny subsidiaries beginning February 25, 2011. FES and the Utilities do not have separate reportable operating segments.

80

The Regulated Distribution segment distributes electricity through our eightFirstEnergy’s ten utility operating companies, serving 4.5approximately 6 million customers within 36,10067,000 square miles of Ohio, Pennsylvania, West Virginia, Virginia, Maryland, New Jersey and New JerseyYork, and purchases power for its POLR and default service requirements in Ohio, Pennsylvania and New Jersey. ItsThis 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 ourFirstEnergy’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 (default(POLR or default service) in its Ohio, Pennsylvania andMaryland, 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. Its revenues are primarily derived from the formula rate recovery of costs and a return on debt and equity for capital expenditures in connection with TrAIL, PATH and other projects and revenues from providing transmission services to electric energy providers, power marketers and receiving transmission-related revenues from operation of a portion of the FirstEnergy transmission system. Its results reflect the net PJM and MISO transmission expenses related to the delivery of the respective generation loads andloads. On June 1, 2011, the deferral and amortizationATSI transmission assets currently dedicated to MISO are scheduled to be integrated into the PJM market. This integration brings all of certain fuel costs.
FirstEnergy’s assets into one RTO.
The Competitive Energy Services segment, through FES, 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 POLR and default service requirements of ourFirstEnergy’s Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Maryland, Michigan and New Jersey. 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.
The Competitive Energy Services segment also includes Allegheny’s unregulated electric generation operations, including AE Supply and AE Supply’s interest in AGC. AE Supply owns, operates and controls the electric generation capacity of its 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 business segment controls approximately 14,000 MW20,000 MWs of capacity and also purchases electricity to meet sales obligations. The segment’s net income is primarily derived from affiliated and non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO to deliver energy to the segment’s customers.
The Other segment contains corporate items and other businesses that are below the quantifiable threshold for separate disclosure as a reportable segment.

 

6681

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 1213 to the consolidated financial statements. Earnings available to FirstEnergy by major business segment were as follows:
                                    
 Three Months Ended Nine Months Ended  Three Months Ended   
 September 30 September 30  March 31 Increase 
 Increase Increase  2011 2010 (Decrease) 
 2010 2009 (Decrease) 2010 2009 (Decrease)  (In millions, except per share data) 
 (In millions, except per share data) 
Earnings (Loss) By Business Segment:
 
Energy delivery services $224 $148 $76 $481 $285 $196 
Competitive energy services  (27) 183  (210) 174 614  (440)
Earnings By Business Segment:
 
Regulated Distribution $96 $103 $(7)
Competitive Energy Services 5 69  (64)
Regulated Independent Transmission 13 12 1 
Other and reconciling adjustments*  (18)  (97) 79  (56)  (131) 75   (64)  (29)  (35)
                    
Total $179 $234 $(55) $599 $768 $(169) $50 $155 $(105)
                    
  
Basic Earnings Per Share
 $0.59 $0.77 $(0.18) $1.97 $2.52 $(0.55) $0.15 $0.51 $(0.36)
Diluted Earnings Per Share
 $0.59 $0.77 $(0.18) $1.96 $2.51 $(0.55) $0.15 $0.51 $(0.36)
* 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 — ThirdFirst Quarter 20102011 Compared with ThirdFirst Quarter 20092010
Financial results for FirstEnergy’s major business segments in the thirdfirst quarter of 20102011 and 20092010 were as follows:
                                    
 Energy Competitive Other and    Competitive Regulated Other and   
 Delivery Energy Reconciling FirstEnergy  Regulated Energy Independent Reconciling FirstEnergy 
Third Quarter 2010 Financial Results Services Services Adjustments Consolidated 
First Quarter 2011 Financial Results Distribution Services Transmission Adjustments Consolidated 
 (In millions)  (In millions) 
Revenues:  
External  
Electric $2,609 $905 $— $3,514  $2,175 $1,162 $— $— $3,337 
Other 148 52  (21) 179  93 92 67  (45) 207 
Internal 60 599  (659) —  — 343 —  (311) 32 
                    
Total Revenues 2,817 1,556  (680) 3,693  2,268 1,597 67  (356) 3,576 
                    
  
Expenses:  
Fuel — 401  (1) 400  24 429 — — 453 
Purchased power 1,473 470  (659) 1,284  1,179 318 —  (311) 1,186 
Other operating expenses 422 347  (31) 738  386 648 17  (18) 1,033 
Provision for depreciation 111 62 9 182  116 88 10 6 220 
Amortization of regulatory assets 176 — — 176  129 — 3 — 132 
Deferral of new regulatory assets — — — —  — — — — — 
Impairment of long lived assets — 292 — 292 
General taxes 174 26 6 206  176 44 8 9 237 
Impairment of long-lived assets — — — — — 
                    
Total Expenses 2,356 1,598  (676) 3,278  2,010 1,527 38  (314) 3,261 
                    
  
Operating Income 461  (42)  (4) 415  258 70 29  (42) 315 
                    
Other Income (Expense):  
Investment income 23 28  (5) 46  25 6 —  (10) 21 
Interest expense  (125)  (53)  (30)  (208)  (132)  (78)  (9)  (12)  (231)
Capitalized interest 2 23 16 41  1 10 — 7 18 
                    
Total Other Expense  (100)  (2)  (19)  (121)  (106)  (62)  (9)  (15)  (192)
                    
  
Income Before Income Taxes 361  (44)  (23) 294  152 8 20  (57) 123 
Income taxes 137  (17)  (1) 119  56 3 7 12 78 
                    
Net Income (Loss) 224  (27)  (22) 175  96 5 13  (69) 45 
Loss attributable to noncontrolling interest — —  (4)  (4) — — —  (5)  (5)
                    
Earnings available to FirstEnergy Corp. $224 $(27) $(18) $179  $96 $5 $13 $(64) $50 
                    

 

6782

                 
  Energy  Competitive  Other and    
  Delivery  Energy  Reconciling  FirstEnergy 
Third Quarter 2009 Financial Results Services  Services  Adjustments  Consolidated 
  (In millions) 
Revenues:                
External                
Electric $2,804  $444  $—  $3,248 
Other  138   46   (24)  160 
Internal  —   617   (617)  — 
             
Total Revenues  2,942   1,107   (641)  3,408 
             
                 
Expenses:                
Fuel  —   302   —   302 
Purchased power  1,725   205   (617)  1,313 
Other operating expenses  366   331   (32)  665 
Provision for depreciation  112   69   7   188 
Amortization of regulatory assets  261   —   —   261 
Deferral of new regulatory assets  —   —   —   — 
Impairment of long lived assets  —   —   —   — 
General taxes  162   27   3   192 
             
Total Expenses  2,626   934   (639)  2,921 
             
                 
Operating Income  316   173   (2)  487 
             
Other Income (Expense):                
Investment income  46   159   (14)  191 
Interest expense  (116)  (46)  (193)  (355)
Capitalized interest  1   18   16   35 
             
Total Other Expense  (69)  131   (191)  (129)
             
                 
Income Before Income Taxes  247   304   (193)  358 
Income taxes  99   121   (92)  128 
             
Net Income (Loss)  148   183   (101)  230 
Loss attributable to noncontrolling interest  —   —   (4)  (4)
             
Earnings available to FirstEnergy Corp. $148  $183  $(97) $234 
             
                                    
Changes Between Third Quarter 2010 and Energy Competitive Other and   
Third Quarter 2009 Financial Results Delivery Energy Reconciling FirstEnergy 
Increase (Decrease) Services Services Adjustments Consolidated 
 Competitive Regulated Other and   
 Regulated Energy Independent Reconciling FirstEnergy 
First Quarter 2010 Financial Results Distribution Services Transmission Adjustments Consolidated 
 (In millions)  (In millions) 
Revenues:  
External  
Electric $(195) $461 $— $266  $2,398 $669 $— $— $3,067 
Other 10 6 3 19  86 50 57  (28) 165 
Internal 60  (18)  (42) —  — 674 —  (607) 67 
                    
Total Revenues  (125) 449  (39) 285  2,484 1,393 57  (635) 3,299 
                    
  
Expenses:  
Fuel — 99  (1) 98  — 334 — — 334 
Purchased power  (252) 265  (42)  (29) 1,395 450 —  (607) 1,238 
Other operating expenses 56 16 1 73  359 352 14  (24) 701 
Provision for depreciation  (1)  (7) 2  (6) 104 77 9 3 193 
Amortization of regulatory assets  (85) — —  (85) 209 — 3 — 212 
Deferral of new regulatory assets — — — —  — — — — — 
Impairment of long lived assets — 292 — 292 
General taxes 12  (1) 3 14  154 37 7 7 205 
Impairment of long-lived assets — — — — — 
                    
Total Expenses  (270) 664  (37) 357  2,221 1,250 33  (621) 2,883 
                    
  
Operating Income 145  (215)  (2)  (72) 263 143 24  (14) 416 
                    
Other Income (Expense):  
Investment income  (23)  (131) 9  (145) 26 1 —  (11) 16 
Interest expense  (9)  (7) 163 147   (125)  (56)  (5)  (27)  (213)
Capitalized interest 1 5 — 6  1 23 — 17 41 
                    
Total Other Expense  (31)  (133) 172 8   (98)  (32)  (5)  (21)  (156)
                    
  
Income Before Income Taxes 114  (348) 170  (64) 165 111 19  (35) 260 
Income taxes 38  (138) 91  (9) 62 42 7 — 111 
                    
Net Income (Loss) 76  (210) 79  (55) 103 69 12  (35) 149 
Loss attributable to noncontrolling interest — — — —  — — —  (6)  (6)
                    
Earnings available to FirstEnergy Corp. $76 $(210) $79 $(55) $103 $69 $12 $(29) $155 
                    

 

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Changes Between First Quarter 2011     Competitive  Regulated  Other and    
and First Quarter 2010 Financial Regulated  Energy  Independent  Reconciling  FirstEnergy 
Results Increase (Decrease) Distribution  Services  Transmission  Adjustment  Consolidated 
  (In millions) 
Revenues:                    
External                    
Electric $(223) $493  $—  $—  $270 
Other  7   42   10   (17)  42 
Internal  —   (331)  —   296   (35)
                
Total Revenues  (216)  204   10   279   277 
                
                     
Expenses:                    
Fuel  24   95   —   —   119 
Purchased power  (216)  (132)  —   296   (52)
Other operating expenses  27   296   3   6   332 
Provision for depreciation  12   11   1   3   27 
Amortization of regulatory assets  (80)  —   —   —   (80)
Deferral of new regulatory assets  —   —   —   —   — 
General taxes  22   7   1   2   32 
Impairment of long-lived assets  —   —   —   —   — 
                
Total Expenses  (211)  277   5   307   378 
                
                     
Operating Income  (5)  (73)  5   (28)  (101)
                
Other Income (Expense):                    
Investment income  (1)  5   —   1   5 
Interest expense  (7)  (22)  (4)  15   (18)
Capitalized interest  —   (13)  —   (10)  (23)
                
Total Other Expense  (8)  (30)  (4)  6   (36)
                
                     
Income Before Income Taxes  (13)  (103)  1   (22)  (137)
Income taxes  (6)  (39)  —   12   (33)
                
Net Income (Loss)  (7)  (64)  1   (34)  (104)
Loss attributable to noncontrolling interest  —   —   —   1   1 
                
Earnings available to FirstEnergy Corp. $(7) $(64) $1  $(35) $(105)
                
Energy Delivery ServicesRegulated Distribution — ThirdFirst Quarter 2011 Compared with First Quarter 2010 Compared with Third Quarter 2009
Net income increaseddecreased by $76$7 million in the thirdfirst quarter of 2011 compared to the first quarter of 2010, compared to the third quarter of 2009, primarily due to higher distribution revenues. Lowerlower generation and transmission revenues wereand merger-related costs associated with the Allegheny merger, partially offset by lower purchased power expenses.costs and amortization of regulatory assets.

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Revenues —-
The decrease in total revenues resulted from the following sources:
                        
 Three Months    Three Months   
 Ended September 30 Increase  Ended March 31 Increase 
Revenues by Type of Service 2010 2009 (Decrease)  2011 2010 (Decrease) 
 (In millions)  (In millions) 
Pre-merger companies
 
Distribution services $1,041 $915 $126  $909 $883 $26 
              
Generation sales:  
Retail 1,266 1,551  (285) 873 1,178  (305)
Wholesale 231 195 36  116 217  (101)
              
Total generation sales 1,497 1,746  (249) 989 1,395  (406)
              
Transmission 223 232  (9) 37 160  (123)
Other 56 49 7  58 46 12 
              
Total pre-merger companies 1,993 2,484  (491)
       
Allegheny companies 275 — 275 
       
Total Revenues $2,817 $2,942 $(125) $2,268 $2,484 $(216)
              
The increase in distribution service revenues reflected an $88 million increase duehigher distribution deliveries in the first quarter of 2011 compared to higher sales volumes and a $38 million increase duethe same period in 2010. Distribution deliveries (excluding the Allegheny companies) increased 650,000 MWH (2.4%) to a change27,538,000 MWH in prices.the first quarter of 2011 from 26,888,000 MWH in the first quarter of 2010. The increase in distribution deliveries by customer class is summarized in the following table:
Electric Distribution KWH Deliveries
Residential19%
Commercial5%
Industrial11%
Total Distribution KWH Deliveries12%
             
          Increase 
Electric Distribution KWH Deliveries 2011  2010  (Decrease) 
  (in thousands)         
             
Pre-merger companies
            
Residential  10,638   10,455   1.8%
Commercial  7,929   7,953   (0.3)%
Industrial  8,841   8,351   5.9%
Other  130   129   0.8%
          
Total pre-merger companies  27,538   26,888   2.4%
          
Allegheny companies  3,540   —   — 
          
Total Electric Distribution MWH Deliveries  31,078   26,888   15.6%
          
Higher deliveries to residential and commercial customers reflected increased weather-related usage in the thirdfirst quarter of 2010,2011, as coolingheating degree days increased by 60%5.2% from the same period in 2009.2010. The increase in distribution deliveries to industrial customers was primarily due to recovering economic conditions in FirstEnergy’s service territory compared to the thirdfirst quarter of 2009.2010. In the industrial sector, KWH deliveries increased by 12.8% to major automotivesteel customers, (14%),4.7% to refinery customers (28%) and steel customers (45%). The increase in distribution service revenues also includes the recovery of Pennsylvania Energy Efficiency and Conservation charges ($21 million) as approved by the PPUC in March 2010.8.4% to chemical customers.
The following table summarizes the price and volume factors contributing to the $249$406 million decrease in generation revenues in the thirdfirst quarter of 20102011 compared to the thirdfirst quarter of 2009:2010:
        
 Increase  Increase 
Source of Change in Generation Revenues (Decrease)  (Decrease) 
 (In millions)  (In millions) 
 
Retail:  
Effect of 19.8% decrease in sales volumes $(307)
Effect of 32.4% decrease in sales volumes $(382)
Change in prices 22  77 
      
  (285)  (305)
      
 
Wholesale:  
Effect of 3.1% increase in sales volumes 6 
Effect of 3.9% increase in sales volumes 8 
Change in prices 30   (109)
      
 36   (101)
      
Net Decrease in Generation Revenues $(249) $(406)
      

 

6985

The decrease in retail generation sales volumes was primarily due to an increase in customer shopping in the Ohio Companies’, Met-Ed’s and Penelec’s service territories in the thirdfirst quarter of 2011, compared to the first quarter of 2010. That condition is expected to continue to impact the comparative sales levels for the remainder of 2010. Total generation KWH provided by alternative suppliers as a percentage of total KWH deliveries increased to 73% from 53% for the Ohio Companies increasedand to 64%40% from 2% in the third quarter of 2010 from 21% in the third quarter 2009.Met-Ed’s and Penelec’s service areas.
The increasedecrease in wholesale generation revenues reflected increased capacity sales bylower RPM revenues for Met-Ed and Penelec in the PJM market. Transmission revenues decreased $123 million due to the termination of Met-Ed’s and Penelec’s transmission tariff effective January 1, 2011. Transmission costs are now a component of the cost of generation established under Met-Ed’s and Penelec’s generation procurement plan.
The Allegheny companies added $275 million in revenues for the first quarter of 2011, including $69 million for distribution services, $190 million for generation sales and $16 million relating to PJM transmission revenues.
Expenses -—
Total expenses decreased by $270$140 million due to the following:
Purchased power costs, excluding the Allegheny companies, were $252$356 million lower in the thirdfirst quarter of 20102011 due primarily to a decrease in volumes needed to serve the lower sales volumes.volume requirements. The decrease in power purchased from non-affiliates was partially offset by an increase in purchases from FES. The decrease in purchased power volumes from non-affiliates resulted principally fromFES reflected the termination of a third-party supply contract for Met-Ed and Penelec in January 2010 and from the above described increase in customer shopping indescribed above and the Ohio Companies’ service territories.
Prices paid for power purchased from non-affiliates in the third quarter of 2010 resulted from higher capacity prices in the PJM market for Met-Ed and Penelec compared to the third quarter of 2009, which is expected to continue for the remainder of the year. The decrease in unit costs on purchases from FES reflected a lower weighted average unit price under the Ohio Companies’ CBP and was partially offset by an increase in volume due to the replacementtermination of Met-Ed’s and Penelec’s terminated third-party contractpartial requirements PSA with supplyFES at the end of 2010. The increase in volumes purchased from FES.non-affiliates under Met-Ed’s and Penelec’s generation procurement plan effective January 1, 2011 was offset by a decrease in RPM expenses in the PJM market. The Allegheny companies added $140 million in purchased power costs in the first quarter of 2011.
        
 Increase  Increase 
Source of Change in Purchased Power (Decrease)  (Decrease) 
 (In millions)  (In millions) 
Pre-merger companies
 
Purchases from non-affiliates:  
Change due to increased unit costs $155 
Change due to decreased volumes  (443)
Change due to decreased unit costs $(186)
Change due to increased volumes 188 
      
  (288) 2 
      
Purchases from FES:  
Change due to decreased unit costs  (61)
Change due to increased volumes 45 
Change due to increased unit costs 36 
Change due to decreased volumes  (412)
      
  (16)  (376)
      
  
Decrease in costs deferred 52  18 
      
Total pre-merger companies  (356)
   
Purchases by Allegheny companies 140 
   
Net Decrease in Purchased Power Costs $(252) $(216)
      
Transmission costs increased by $87expenses decreased $98 million in the third quarter of 2010 primarily due to higherlower PJM network transmission expenses and congestion costs of $110 million for Met-Ed and Penelec.Penelec, partially offset by transmission expenses for the Allegheny companies of $12 million in the first quarter of 2011. Met-Ed and Penelec defer or amortize the difference between revenues from their transmission rider and transmission costs incurred with no material effect on current period earnings.
Administrative and generalEnergy Efficiency program costs, including labor and employee benefit expenses, decreased by $28 million due to restructuringwhich are also recovered through rates, increased $16 million.
Material costs recognized in the third quarter of 2009 and lower expenses associated with employee benefit plans.
A decrease in expenses relating to leasehold interests in Perry and Beaver Valley of $21 million in the third quarter of 2010 compared to the third quarter of 2009.
Vegetation management costs charged to operating expenses decreased bymaintenance activities increased $10 million in the thirdfirst quarter of 20102011 compared to the thirdsame period last year.
A provision for excess and obsolete material of $13 million was recognized in the first quarter of 2009.2011 relating to revised inventory practices adopted in conjunction with the Allegheny merger.
Energy efficiency program costsDepreciation expense increased $16$12 million indue to property additions since the thirdfirst quarter of 2010 compared to the third quarter of 2009.2010.

 

7086

Economic development costs associated with the Ohio Companies’ ESP increased by $10 million in the third quarter of 2010.
AmortizationNet amortization of regulatory assets decreased $85$80 million indue primarily to generation-related rate deferrals for the third quarter of 2010 principally due to lowerOhio Companies, Met-Ed and Penelec and reduced net MISO and PJM transmission cost amortization compared to the third quarter of 2009.amortization.
General taxes increased $12$22 million primarily due to higher property taxes and gross receipts taxes in the thirdfirst quarter of 2010.2011.
Fuel expenses for MP were $24 million in the first quarter of 2011.         
Operating expenses for the Allegheny companies were $38 million in the first quarter of 2011.
Merger-related costs incurred by the Allegheny companies were $48 million in the first quarter of 2011.
Other Expense -—
Other expense increased $31$8 million in the thirdfirst quarter of 2011 due to interest expense on debt of the Allegheny companies.
Regulated Independent Transmission — First Quarter 2011 Compared with First Quarter 2010
Net income increased by $1 million in the first quarter of 2011 compared to the first quarter of 2010 compareddue to earnings associated with TrAIL and PATH ($5 million), partially offset by reduced earnings for ATSI ($4 million).
Revenues —
Revenues by transmission asset owner are shown in the third quarter of 2009following table:
             
  Three Months    
Revenues by Ended March 31  Increase 
Transmission Asset Owner 2011  2010  (Decrease) 
  (In millions) 
ATSI $52  $57  $(5)
TrAIL  14   —   14 
PATH  1   —   1 
          
Total Revenues $67  $57  $10 
          
Expenses —
Total expenses increased by $5 million due primarily to lower investment income relatedoperating expenses associated with TrAIL and PATH, which were $3 million in the first quarter of 2011.
Other Expense —
Other expense increased $4 million in the first quarter of 2011 due to OE’s and TE’s nuclear decommissioning trusts ($23 million) and higheradditional interest expense associated with debt issuances by the Utilities since the third quarter of 2009 ($8 million).
TrAIL.
Competitive Energy Services — ThirdFirst Quarter 20102011 Compared with ThirdFirst Quarter 20092010
Net income decreased by $210$64 million in the thirdfirst quarter of 2011, compared to the first quarter of 2010, compared to the third quarter of 2009, primarily due to a $292 million impairment charge ($181 million netincreased transmission expense, an inventory reserve adjustment, non-core asset impairments and the effect of tax) related to operational changes at certain smaller coal-fired units in response to the continued slow economy, lower demand for electricity and uncertainty related to proposed new federal environmental regulations. In addition, net income decreased due to lower investment income from the nuclear decommissioning trusts, partially offset by increased sales margins.mark-to-market adjustments.
Revenues -—
Total revenues increased $449$204 million in the thirdfirst quarter of 20102011 primarily due to growth in direct and government aggregation sales and POLR sales volumes,the inclusion of the Allegheny companies, partially offset by a decline in wholesalePOLR sales.

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The increase in total revenues resulted from the following sources:
                        
 Three Months    Three Months   
 Ended September 30 Increase  Ended March 31 Increase 
Revenues by Type of Service 2010 2009 (Decrease)  2011 2010 (Decrease) 
 (In millions)  (In millions) 
 
Direct and Government Aggregation $840 $512 $328 
POLR 369 673  (304)
Wholesale 96 91 5 
Transmission 26 17 9 
REC’s 32 67  (35)
Other 41 33 8 
Allegheny Companies 193 — 193 
       
Total Revenues $1,597 $1,393 $204 
       
 
Allegheny Companies
 
Direct and Government Aggregation $717 $232 $485  $9 
POLR 652 636 16  68 
Wholesale 136 192  (56) 91 
Transmission 22 17 5  12 
Other 29 30  (1) 13 
          
Total Revenues $1,556 $1,107 $449  $193 
          
 
 Three Months   
 Ended March 31 Increase 
MWH Sales by Type of Service 2011 2010 (Decrease) 
 (In thousands) 
Direct 9,671 5,854  65.2%
Government Aggregation 4,310 2,732  57.8%
POLR 5,714 13,276  (57.0)%
Wholesale 1,113 898  23.9%
Allegheny Companies 2,636 — — 
       
Total Sales 23,444 22,760  3.0%
       
 
Allegheny Companies
 
Direct 145 
POLR 812 
Structured Sales 284 
Wholesale 1,395 
   
Total Sales 2,636 
   
The increase in direct and government aggregation revenues of $485$328 million resulted from increased revenue from the acquisition of new commercial and industrial customers as well as new government aggregation contracts with communities in Ohio that provided generation to 1.2approximately 1.5 million residential and small commercial customers at the end of September 2010March 2011 compared to 500,000approximately 1.1 million such customers at the end of September 2009.March 2010. In addition, sales to residential and small commercial customers were bolstered by weather in the delivery area that was 60% warmer5.2% colder than in 2009.2010.

88

The increasedecrease in POLR revenues of $16$304 million was due to higherlower sales volumes to the Pennsylvania Companies and non-associated companies,Ohio Companies, partially offset by decreasedincreased sales volumes to the Ohio Companiesnon-associated companies and lowerhigher unit prices to both the Ohio Companies and the Pennsylvania Companies. The increased revenues fromParticipation in POLR auctions and RFPs are expected to continue, but the Pennsylvania Companies resulted from FES supplying Met-Edconcentration of these sales will primarily be dependent on our success in our direct retail and Penelec with volumes previously supplied through a third-party contract and at prices that were slightly higher than in the third quarter of 2009.aggregation sales channels.
Wholesale revenues decreased $56increased $5 million due to reducedincreased volumes andpartially offset by lower wholesale prices. The lowerhigher sales volumes were athe result of using available capacityincreased short term (net hourly positions) transactions in MISO. $22 million of wholesale revenue resulted from long positions in MISO that were unable to serve increased retail salesbe netted with short positions in Ohio. In July 2010, FES entered into financial transactions that offset a portion of the mark-to-market impact of legacy purchased power contracts totaling 500 MW entered into in 2008 for delivery in 2010 and 2011 that have been markedPJM, due to market since December 2009. These financial transactions mitigate the volatility of these contracts through the end of 2011 and resulted in wholesale revenues of $13 million for the quarter ended September 2010.separate settlement requirements with each RTO.

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The following tables summarize the price and volume factors contributing to changes in revenues:revenues (excluding the Allegheny companies):
     
  Increase 
Source of Change in Direct and Government Aggregation (Decrease) 
  (In millions) 
Direct Sales:    
Effect of increase in sales volumes $277 
Change in prices  (28)
    
   249 
    
Government Aggregation:    
Effect of increase in sales volumes  232 
Change in prices  4 
    
   236 
    
Net Increase in Direct and Government Aggregation Revenues $485 
    
    
 Increase 
Source of Change in Direct and Government Aggregation (Decrease) 
 (In millions) 
Direct Sales: 
Effect of 65.2% increase in sales volumes $223 
Change in prices  (4)
   
 219 
   
Government Aggregation: 
Effect of 57.8% increase in sales volumes 100 
Change in prices 9 
   
 109 
   
Net Increase in Direct and Government Aggregation Revenues $328 
   
   
 Increase 
Source of Change in POLR Revenues (Decrease) 
 (In millions) 
POLR: 
Effect of 57.0% decrease in sales volumes $(384)
Change in prices 80 
   
  (304)
   
       
 Increase  Increase 
Source of Change in Wholesale Revenues (Decrease)  (Decrease) 
 (In millions)  (In millions) 
POLR: 
Effect of 8.6% increase in sales volumes $55 
Other Wholesale: 
Effect of 23.9% increase in sales volumes 12 
Change in prices  (39)  (7)
      
 16  5 
      
Other Wholesale: 
Effect of 25.9% decrease in sales volumes  (29)
Change in prices  (27)
   
  (56)
   
Net Decrease in Wholesale Revenues $(40)
   
Transmission revenues increased $5$9 million due primarily to higher MISO congestion revenue. The revenues derived from the sale of RECs declined $35 million in the first quarter of 2011.
Expenses -—
Total expenses increased $664$277 million in the thirdfirst quarter of 20102011 due to the following:
Fuel costs increased $99$13 million primarily due to increased volumes ($31 million), partially offset by lower unit prices.prices ($18 million). Volumes increased due to higher generation at the fossil units. Unit prices declined primarily due to coal blend changesimproved generating unit availability at more efficient units, partially offset by increased coal transportation expensescosts and higher nuclear fuel unit prices following the refueling outages that occurred in 2009.2010.
Purchased power costs increased $265decreased $153 million due primarily to higherlower volumes purchased ($246185 million) and a power contract mark-to-market adjustment ($26 million), partially offset by lowerhigher unit costs ($732 million). The increasedecrease in volume primarily relates to the assumptionabsence in 2011 of a 1,300 MW third party contract fromassociated with serving Met-Ed and Penelec. $35 million of purchased power expense resulted from long positions in MISO that were unable to be netted with short positions in PJM, due to separate settlement requirements with each RTO.
Fossil operating costs decreased $16increased $1 million due primarily to higher labor costs partially offset by lower staffing levels, more capital related workprofessional and contractor costs and reduced coal storage limitation charges.sale losses.
Nuclear operating costs decreased $2increased $15 million due primarily to lowerhigher labor and related benefits, partially offset by higherlower professional and contractor costs in connection with refueling outages.costs.

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Transmission expenses increased $4$111 million due primarily to increases in MISOPJM of $46$108 million from higher congestion, network, ancillary and congestion costs, partially offset by lower PJMloss expense and MISO transmission expenses of $42$3 million due to lowerhigher congestion costs.
General taxes increased $3 million due to an increase in revenue-related taxes.
Other expenses increased $314$65 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 $292$13 million impairment charge ($181 million net of tax) related to operational changes at Bay Shore units 2-4, Eastlake Plant units 1-4,non-core assets; an $11 million increase in intercompany billings; and reduced mark-to-market adjustments of $15 million.
The inclusion of approximately one month of the Lake Shore Plant and the Ashtabula Plant. In addition, increased costs were incurred in uncollectible customer accounts and agent fees associated with the growth in direct and government aggregation sales.
Allegheny companies’ operations contributed $222 million to expenses, including a $29 million mark-to-market adjustment relating primarily to power contracts.
Other Expense -—
Total other expense in the thirdfirst quarter of 20102011 was $133$30 million higher than the thirdfirst quarter of 2009,2010, primarily due to a decrease$35 million increase in net interest expense partially offset by an increase in nuclear decommissioning trust investment income ($1315 million). The increase in interest expense was primarily due to the inclusion of the Allegheny companies ($20 million) and a $2 million increase in netlower capitalized interest expense from new long-term debt issued by FES in August 2009 combined($13 million) associated with the restructuringcompletion of existing PCRBs.the Sammis AQC project in 2010.

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Other — ThirdFirst Quarter of 20102011 Compared with ThirdFirst Quarter of 20092010
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 $79$35 million increasedecrease in earnings available to FirstEnergy in the thirdfirst quarter of 20102011 compared to the same period in 2009.2010. The increasedecrease resulted primarily from the absence of debt retirement costs that were incurred in the third quarter of 2009 in connectionreduced other revenues ($17 million) representing reconciling adjustments combined with a September 2009 tender offer for holding company debt ($139 million), decreased interest expense resulting from that tender offer ($13 million) and increased investment income ($9 million), partially offset by increased income tax expensetaxes ($9112 million).
Summary of Results of Operations — First Nine Months of 2010 Compared with the First Nine Months of 2009
Financial results for FirstEnergy’s major business segments in the first nine months of 2010 and 2009 were as follows:
                 
  Energy  Competitive  Other and    
  Delivery  Energy  Reconciling  FirstEnergy 
First Nine Months 2010 Financial Results Services  Services  Adjustments  Consolidated 
  (In millions) 
Revenues:                
External                
Electric $7,250  $2,302  $—  $9,552 
Other  423   151   (71)  503 
Internal*  79   1,812   (1,824)  67 
             
Total Revenues  7,752   4,265   (1,895)  10,122 
             
                 
Expenses:                
Fuel  —   1,089   (5)  1,084 
Purchased power  4,159   1,239   (1,824)  3,574 
Other operating expenses  1,154   1,031   (73)  2,112 
Provision for depreciation  339   194   32   565 
Amortization of regulatory assets  549   —   —   549 
Deferral of new regulatory assets  —   —   —   — 
Impairment of long lived assets  —   294   —   294 
General taxes  481   86   20   587 
             
Total Expenses  6,682   3,933   (1,850)  8,765 
             
                 
Operating Income  1,070   332   (45)  1,357 
             
Other Income (Expense):                
Investment income  75   42   (24)  93 
Interest expense  (373)  (161)  (94)  (628)
Capitalized interest  4   67   51   122 
             
Total Other Expense  (294)  (52)  (67)  (413)
             
                 
Income Before Income Taxes  776   280   (112)  944 
Income taxes  295   106   (37)  364 
             
Net Income (Loss)  481   174   (75)  580 
Loss attributable to noncontrolling interest  —   —   (19)  (19)
             
Earnings available to FirstEnergy Corp. $481  $174  $(56) $599 
             

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  Energy  Competitive  Other and    
  Delivery  Energy  Reconciling  FirstEnergy 
First Nine Months 2009 Financial Results Services  Services  Adjustments  Consolidated 
  (In millions) 
Revenues:                
External                
Electric $8,322  $929  $—  $9,251 
Other  433   400   (71)  762 
Internal  —   2,349   (2,349)  — 
             
Total Revenues  8,755   3,678   (2,420)  10,013 
             
                 
Expenses:                
Fuel  —   890   —   890 
Purchased power  5,278   551   (2,349)  3,480 
Other operating expenses  1,191   1,001   (89)  2,103 
Provision for depreciation  331   201   18   550 
Amortization of regulatory assets  903   —   —   903 
Deferral of new regulatory assets  (136)  —   —   (136)
Impairment of long lived assets  —   —   —   — 
General taxes  486   84   17   587 
             
Total Expenses  8,053   2,727   (2,403)  8,377 
             
                 
Operating Income  702   951   (17)  1,636 
             
Other Income (Expense):                
Investment income  111   136   (40)  207 
Interest expense  (341)  (106)  (308)  (755)
Capitalized interest  3   42   51   96 
             
Total Other Expense  (227)  72   (297)  (452)
             
                 
Income Before Income Taxes  475   1,023   (314)  1,184 
Income taxes  190   409   (169)  430 
             
Net Income (Loss)  285   614   (145)  754 
Loss attributable to noncontrolling interest  —   —   (14)  (14)
             
Earnings available to FirstEnergy Corp. $285  $614  $(131) $768 
             
                 
Changes Between First Nine Months 2010 Energy  Competitive  Other and    
and First Nine Months 2009 Financial Results Delivery  Energy  Reconciling  FirstEnergy 
Increase (Decrease) Services  Services  Adjustments  Consolidated 
  (In millions) 
Revenues:                
External                
Electric $(1,072) $1,373  $—  $301 
Other  (10)  (249)  —   (259)
Internal*  79   (537)  525   67 
             
Total Revenues  (1,003)  587   525   109 
             
                 
Expenses:                
Fuel  —   199   (5)  194 
Purchased power  (1,119)  688   525   94 
Other operating expenses  (37)  30   16   9 
Provision for depreciation  8   (7)  14   15 
Amortization of regulatory assets  (354)  —   —   (354)
Deferral of new regulatory assets  136   —   —   136 
Impairment of long lived assets  —   294   —   294 
General taxes  (5)  2   3   — 
             
Total Expenses  (1,371)  1,206   553   388 
             
                 
Operating Income  368   (619)  (28)  (279)
             
Other Income (Expense):                
Investment income  (36)  (94)  16   (114)
Interest expense  (32)  (55)  214   127 
Capitalized interest  1   25   —   26 
             
Total Other Expense  (67)  (124)  230   39 
             
                 
Income Before Income Taxes  301   (743)  202   (240)
Income taxes  105   (303)  132   (66)
             
Net Income (Loss)  196   (440)  70   (174)
Loss attributable to noncontrolling interest  —   —   (5)  (5)
             
Earnings available to FirstEnergy Corp. $196  $(440) $75  $(169)
             
*Under the accounting standard for the effects of certain types of regulation, internal revenues are not fully offset for sale of RECs by FES to the Ohio Companies that are retained in inventory.

74

Energy Delivery Services — First Nine Months of 2010 Compared to First Nine Months of 2009
Net income increased by $196 million in the first nine months of 2010, compared to the first nine months of 2009, primarily due to the absence of CEI’s $216 million regulatory asset impairment in 2009, partially offset by decreases in other operating expenses. Lower generation revenues were offset by lower purchased power expenses.
Revenues -
The decrease in total revenues resulted from the following sources:
             
  Nine Months    
  Ended September 30  Increase 
Revenues by Type of Service 2010  2009  (Decrease) 
  (In millions) 
Distribution services $2,774  $2,578  $196 
          
Generation sales:            
Retail  3,540   4,679   (1,139)
Wholesale  628   544   84 
          
Total generation sales  4,168   5,223   (1,055)
          
Transmission  638   808   (170)
Other  172   146   26 
          
Total Revenues $7,752  $8,755  $(1,003)
          
The increase in distribution deliveries by customer class is summarized in the following table:
Electric Distribution KWH Deliveries
Residential7%
Commercial3%
Industrial10%
Total Distribution KWH Deliveries7%
Higher deliveries to residential and commercial customers reflected increased weather-related usage in the first nine months of 2010. Cooling degree days increased by 69%, partially offset by an 11% decrease in heating degree days from the same period in 2009. In the industrial sector, KWH deliveries increased to major automotive customers (22%), refinery customers (11%) and steel customers (44%) due to recovering economic conditions. The increase in distribution service revenues also reflects the recovery of the Pennsylvania Energy Efficiency and Conservation charges as approved by the PPUC in March 2010 and the accelerated recovery of deferred distribution costs in Ohio, partially offset by a reduction in the transition rate for CEI effective June 1, 2009.
The following table summarizes the price and volume factors contributing to the $1.1 billion decrease in generation revenues in the first nine months of 2010 compared to the same period of 2009:
     
  Increase 
Source of Change in Generation Revenues (Decrease) 
  (In millions) 
Retail:    
Effect of 26.8% decrease in sales volumes $(1,254)
Change in prices  115 
    
   (1,139)
    
Wholesale:    
Effect of 7.1% decrease in sales volumes  (38)
Change in prices  122 
    
   84 
    
Net Decrease in Generation Revenues $(1,055)
    
The decrease in retail generation sales volumes was primarily due to an increase in customer shopping in the Ohio Companies’ service territories in the first nine months of 2010. That condition is expected to continue to impact the comparative sales levels for the remainder of 2010. Total generation KWH provided by alternative suppliers as a percentage of total KWH deliveries for the Ohio Companies increased to 60% in the first nine months of 2010 from 7% in the same period of 2009. Higher generation revenues related to the recovery of transmission costs now provided for in the generation rate established under the May 2009 Ohio CBP partially offset the decrease in sales volumes.
The increase in wholesale generation revenues reflected higher prices and increased capacity sales by Met-Ed and Penelec in the PJM market.

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Transmission revenues decreased $170 million primarily due to the termination of the Ohio Companies’ transmission tariff effective June 1, 2009; recovery of transmission costs is now through the generation rate established under the May 2009 Ohio CBP.
Expenses -
Total expenses decreased by $1.4 billion due to the following:
Purchased power costs were $1.1 billion lower in the first nine months of 2010 in large part due to lower requirements to serve the lower sales volumes. 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 an increase in customer shopping in the Ohio Companies’ service territories described above. The decrease in volumes from FES also resulted from the increase in customer shopping in Ohio.
The increase in purchased power unit costs from non-affiliates in the first nine months of 2010 resulted from higher capacity prices in the PJM market for Met-Ed and Penelec compared to the first nine months of 2009. The decrease in unit costs from FES was principally due to the lower weighted average unit price per KWH for the Ohio Companies established under the May 2009 CBP auction effective June 1, 2009.
     
  Increase 
Source of Change in Purchased Power (Decrease) 
  (In millions) 
Purchases from non-affiliates:    
Change due to increased unit costs $506 
Change due to decreased volumes  (1,140)
    
   (634)
    
Purchases from FES:    
Change due to decreased unit costs  (230)
Change due to decreased volumes  (289)
    
   (519)
    
     
Decrease in costs deferred  34 
    
Net Decrease in Purchased Power Costs $(1,119)
    
Labor and employee benefit expenses decreased by $61 million due to lower pension and OPEB expenses and restructuring expenses recognized in 2009, and lower payroll costs resulting primarily from staffing reductions implemented in 2009.
Uncollectible expenses decreased $12 million due to lower generation revenues in Ohio in the first nine months of 2010 compared to the same period in 2009.
Expenses for economic development commitments related to the Ohio Companies’ ESP were lower by $11 million in the first nine months of 2010 compared to the same period of 2009.
Transmission expenses increased $44 million primarily due to higher PJM network transmission expenses and congestion costs, partially offset by lower MISO network transmission expenses that are not reflected in the generation rate established under the May 2009 Ohio CBP.
Amortization of regulatory assets decreased $354 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 a $35 million regulatory asset impairment associated with the Ohio Companies’ ESP.
The deferral of new regulatory assets decreased $136 million in the first nine months of 2010 due to the absence of purchased power cost deferrals for CEI in 2009.
Depreciation expense increased $8 million due to property additions since the third quarter of 2009.
General taxes decreased $5 million due primarily to favorable Ohio and Pennsylvania tax settlements in 2010 partially offset by higher gross receipts taxes.

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Other Expense -
Other expense increased $67 million in the first nine months of 2010 compared to the first nine months of 2009 primarily due to lower nuclear decommissioning trust investment income ($36 million) and higher interest expense associated with debt issuances by the Utilities since the third quarter of 2009 ($31 million).
Regulatory Assets
FirstEnergy and the Utilities prepare their consolidated financial statements in accordance with the authoritative guidance for accounting for certain types of regulation. Under this guidance, regulatory assets represent incurred or accrued costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued liabilitiesamounts that have been deferred because it is probable such amounts willare expected to be returnedcredited to customers through future regulated rates.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. The following table provides the balance of net regulatory assets by Companycompany as of September 30, 2010March 31, 2011 and December 31, 20092010 and changes during the ninethree months then ended:
                        
 September 30, December 31, Increase  March 31, December 31, Increase 
Regulatory Assets 2010 2009 (Decrease)  2011 2010 (Decrease) 
 (In millions)  (In millions) 
OE $413 $465 $(52) $385 $400 $(15)
CEI 420 546  (126) 337 370  (33)
TE 74 70 4  84 72 12 
JCP&L 722 888  (166) 460 513  (53)
Met-Ed 400 357 43  285 296  (11)
Penelec 203 9 194  179 163 16 
Other 14 21  (7)
Other* 354 12 342 
              
Total $2,246 $2,356 $(110) $2,084 $1,826 $258 
              
*2011 includes $343 million related to the Allegheny companies.

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The following table providestables provide information about the composition of net regulatory assets as of September 30, 2010March 31, 2011 and December 31, 20092010 and the changes during the ninethree months then ended:
                        
 September 30, December 31, Increase  March 31, December 31, Increase 
Regulatory Assets by Source 2010 2009 (Decrease)  2011 2010 (Decrease) 
 (In millions)  (In millions) 
Regulatory transition costs $1,168 $1,100 $68  $592 $770 $(178)
Customer shopping incentives 26 154  (128)
Customer receivables for future income taxes 330 329 1  488 326 162 
Loss on reacquired debt 50 51  (1) 56 48 8 
Employee postretirement benefits 17 23  (6) 14 16  (2)
Nuclear decommissioning, decontamination and spent fuel disposal costs  (173)  (162)  (11)  (200)  (184)  (16)
Asset removal costs  (238)  (231)  (7)  (220)  (237) 17 
MISO/PJM transmission costs 194 148 46  280 184 96 
Deferred generation costs 393 369 24  574 386 188 
Distribution costs 392 482  (90) 333 426  (93)
Other 87 93  (6) 167 91 76 
              
Total $2,246 $2,356 $(110) $2,084 $1,826 $258 
              
FirstEnergy had $390 million of net regulatory liabilities as of March 31, 2011, which includes $378 million of net regulatory liabilities acquired as part of the merger with AE that are primarily related to asset removal costs.
Regulatory assets that do not earn a current return totaled approximately $181$297 million as of September 30, 2010 (JCP&L — $40 million, Met-Ed — $124 million, Penelec — $9 million and CEI $5 million). March 31, 2011.
Regulatory assets not earning a current return (primarilyprimarily for certain all-electric residential discounts and municipal taxes by OE, CEI and TE are approximately $53 million, $32 million and $4 million, respectively. The timing of expected recovery of these assets cannot be determined at this time.
Regulatory assets not earning a current return primarily for regulatory transition costs by Met-Ed and employee postretirement benefits)Penelec are approximately $114 million and $5 million, respectively, and are expected to be recovered by 20142020.
Regulatory assets not earning a current return primarily for certain storm damage costs and pension and postretirement benefits by JCP&L and by 2020 for Met-Ed and Penelec.
Competitive Energy Services — First Nine Monthsare approximately $37 million. The timing of 2010 Compared to First Nine Months of 2009
Net income decreased by $440 million in the first nine months of 2010, compared to the first nine months of 2009, primarily due to a $292 million impairment charge ($181 million net of tax) related to operational changes at certain smaller coal-fired units in response to the continued slow economy, lower demand for electricity, as well as uncertainty related to proposed new federal environmental regulations. In addition, the absence of a $252 million ($158 million after tax) gain in 2009 from the sale of a 9% participation interest in OVEC, lower investment income from nuclear decommissioning trusts and a decrease in sales margins also contributed to the decline in net income.

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Revenues -
Excluding the impact of the 2009 gain on the OVEC sale, total revenues increased $839 million in the first nine months of 2010 compared to the same period in 2009 primarily due to an increase in direct and government aggregation sales volumes and sales of RECs, partially offset by decreases in POLR sales to the Ohio Companies and wholesale sales.
The increase in reported segment revenues resulted from the following sources:
             
  Nine Months    
  Ended September 30  Increase 
Revenues by Type of Service 2010  2009  (Decrease) 
  (In millions) 
Direct and Government Aggregation $1,814  $406  $1,408 
POLR  1,911   2,369   (458)
Wholesale  322   503   (181)
Transmission  58   57   1 
RECs  67   —   67 
Sale of OVEC participation interest  —   252   (252)
Other  93   91   2 
          
Total Revenues $4,265  $3,678  $587 
          
The increase in direct and government aggregation revenues of $1,408 million resulted from increased revenue from the acquisition of new commercial and industrial customers, as well as new government aggregation contracts with communities in Ohio that provide generation to 1.2 million residential and small commercial customers at the end of September 2010 compared to 500,000 such customers at the end of September 2009, partially offset by lower unit prices. In addition, sales to residential and small commercial customers were bolstered by weather in the delivery area that was 69% warmer than in 2009.
The decrease in POLR revenues of $458 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 the Pennsylvania Companies. 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 the Pennsylvania Companies resulted from FES supplying Met-Ed and Penelec with volumes previously supplied through a third-party contract and at prices that were slightly higher than in 2009.
Wholesale revenues decreased $181 million due to reduced volumes and lower prices. The lower sales volumes were due to available capacity serving increased retail sales in Ohio. In July 2010, FES entered into financial transactions that offset the mark-to-market impact of legacy purchased power contracts totaling 500 MW entered into in 2008 for delivery in 2010 and 2011 that have been marked to market since December 2009. These financial transactions mitigate the volatilityexpected recovery of these contracts through the end of 2011 and resulted in wholesale revenues of $13assets cannot be determined at this time.
Regulatory assets not earning a current return primarily for certain deferred generation costs are approximately $52 million in 2010.by FirstEnergy’s other utility subsidiaries are expected to be recovered over various periods though 2012.
The sale of RECs resulted in additional gains of $67 million in the nine months ending September 2010.
The following tables summarize the price and volume factors contributing to changes in revenues from generation sales:
     
  Increase 
Source of Change in Direct and Government Aggregation (Decrease) 
  (In millions) 
Direct Sales:    
Effect of increase in sales volumes $909 
Change in prices  (73)
    
   836 
    
Government Aggregation:    
Effect of increase in sales volumes  570 
Change in prices  2 
    
   572 
    
Net Increase in Direct and Government Aggregation Revenues $1,408 
    

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  Increase 
Source of Change in Wholesale Revenues Decrease 
  (In millions) 
POLR:    
Effect of 8.4% decrease in sales volumes $(200)
Change in prices  (258)
    
   (458)
    
Other Wholesale:    
Effect of 44.6% decrease in sales volumes  (147)
Change in prices  (34)
    
   (181)
    
Net Decrease in Wholesale Revenues $(639)
    
Transmission revenues increased $1 million due primarily to higher MISO congestion revenue, offset by lower PJM congestion revenue.
Expenses -
Total expenses increased $1.2 billion in the first nine months of 2010 due to the following factors:
Fuel costs increased $199 million due to increased generation volumes ($140 million) and higher unit prices ($59 million). The increase in unit prices was due primarily to increased coal transportation costs and higher nuclear fuel unit prices following the refueling outages that occurred in 2009.
Purchased power costs increased $688 million due primarily to higher volumes purchased ($606 million), power contract mark-to-market adjustments ($43 million) and higher unit costs ($39 million).
Fossil operating costs decreased $18 million due primarily to lower labor costs which were partially offset by higher professional and contractor costs and reduced gains on the sale of emission allowances.
Nuclear operating costs decreased $39 million due primarily to lower labor, consulting and contractor costs. The nine months ended September 2010 had one less refueling outage and fewer extended outages than the same period of 2009.
Transmission expenses increased $36 million due primarily to increased costs in MISO of $152 million from higher network, ancillary and congestion costs, partially offset by lower PJM transmission expenses of $116 million due to lower congestion costs.
Other expenses increased $340 million primarily due to a $292 million impairment charge ($181 million net of tax) related to operational changes at Bay Shore units 2-4, Eastlake Plant units 1-4, the Lake Shore Plant and the Ashtabula Plant. In addition, increased costs were incurred in uncollectible customer accounts and agent fees associated with the growth in direct and government aggregation sales.
Other Expense -
Total other expense in the nine months ending September 2010 was $124 million higher than the same period in 2009, primarily due to a decrease in nuclear decommissioning trust investment income ($94 million) and a $30 million increase in net interest expense from new long-term debt issued combined with the restructuring of existing PCRBs.
Other — First Nine Months of 2010 Compared to First Nine Months of 2009
Financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a $75 million increase in earnings available to FirstEnergy in the first nine months of 2010 compared to the same period in 2009. The increase resulted primarily from the absence of debt retirement costs that were incurred in the third quarter of 2009 in connection with the tender offer for holding company debt ($139 million), decreased interest expense associated with the debt retirement ($56 million) and increased interest income ($16 million), partially offset by increased depreciation and other operating expenses ($30 million) and income tax expense ($132 million).
CAPITAL RESOURCES AND LIQUIDITY
As of September 30, 2010,March 31, 2011, FirstEnergy had cash and cash equivalents of approximately $632 million$1.1 billion available to fund investments, operations and capital expenditures. To fund liquidity and capital requirements for the balance of 20102011 and beyond, FirstEnergy willmay rely on internal and 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.

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FirstEnergy expects its existing sources of liquidity to remain sufficient to meet its anticipated obligations and those of its subsidiaries. FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. During 2010 and in subsequent years,2011, FirstEnergy expects to satisfy these requirements with a combination of internal cash from operations and external funds from the capital markets as market conditions warrant. FirstEnergy also expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements 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 current liquidity andits capital resource requirements. To mitigate risk, FirstEnergy’s business model stresses financial discipline and a strong focus on execution. Major elements of this business model include the expectation of: projected cash from operations, opportunities for favorable long-term earnings growth asin the transition to competitive generation markets, continues, operational excellence, retail strategybusiness plan execution, well-positioned generation fleet, no speculative trading operations, appropriate long-term commodity hedging positions, manageable capital expenditure program, welladequately funded pension plan, minimal near-term maturities of existing long-term debt, commitment to a strong and secure dividend (dividends declared from time to time on FirstEnergy’s common stock during any annual period may in aggregate vary from the indicated amount due to circumstances considered by FirstEnergy’s Board of Directors at the time of the actual declarations) and a successful merger integration.

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As of September 30, 2010,March 31, 2011, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was principally due to short-term borrowings ($1.0 billion) and the classification of certain variable interest rate PCRBs as currently payable long-term debt.debt and short-term borrowings. Currently payable long-term debt as of September 30, 2010,March 31, 2011, included the following (in millions):
        
Currently Payable Long-term Debt  
PCRBs supported by bank LOCs(1)
 $1,318  $827 
FGCO and NGC unsecured PCRBs(1)
 90  141 
Penelec FMBs(2)
 24 
Penelec unsecured PCRBs 25 
FirstEnergy Corp. unsecured note 250 
NGC collateralized lease obligation bonds 50  50 
Sinking fund requirements 34  49 
Other notes(3)
 74 
Other notes 43 
      
 $1,590  $1,385 
      
(1) Interest rate mode permits individual debt holders to put the respective debt back to the issuer prior to maturity.
(2)Mature in November 2010.
(3)Notes represent Signal Peak third-party debt and will be repaid with proceeds from the October 22, 2010 refinancing of Signal Peak debt. As of September 30, 2010, $11 million matures in October 2010 and $63 million matures in November 2010.
Short-Term Borrowings
FirstEnergy had approximately $1.0 billion$486 million of short-term borrowings as of September 30, 2010March 31, 2011 and $1.2 billion$700 million as of December 31, 2009.2010. FirstEnergy’s available liquidity as of October 22, 2010,April 25, 2011, is summarized in the following table:
                              
 Available  Available 
Company Type Maturity Commitment Liquidity  Type Maturity Commitment Liquidity 
     (In millions)  (In millions) 
FirstEnergy(1)
 Revolving Aug. 2012 $2,750 $1,650  Revolving Aug. 2012 $2,750 $1,983 
FirstEnergy Solutions Term loan Mar. 2011 100 — 
Ohio and Pennsylvania Companies Receivables financing Various(2) 395 245 
AE Revolving Apr. 2013 250 247 
AE Supply(2)
 Revolving Various 1,050 1,000 
FE Utilities & TrAIL Revolving 2013 910 475 
            
 Subtotal $3,245 $1,895    Subtotal $4,960 $3,705 
 Cash — 911    Cash — 1,134 
            
 Total $3,245 $2,806    Total $4,960 $4,839 
            
(1) FirstEnergy Corp. and subsidiary borrowers.
 
(2) Ohio — $250Includes $50 million matures March 30, 2011; Pennsylvania — $145 million matures December 17, 2010 with optional extension terms.for AGC.

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On October 22, 2010, Signal Peak and Global Rail entered into a $350 million syndicated two-year senior secured term loan facility among the two limited liability companies that comprise Signal Peak and Global Rail, as borrowers, Sovereign Bank, CoBank, Credit Agricole, U.S. Bank, BBVA Compass, Royal Bank of Canada, Fifth Third, Comerica Bank, CIBC Inc. and First Merit banks, as lenders, and Union Bank, N.A. as lender, administrative agent, collateral agent and syndication agent. FirstEnergy, together with WMB Loan Ventures LLC and WMB Loan Ventures II LLC, the entities that share ownership with FEV in the borrowers, have provided a guaranty of the borrowers’ obligations under the facility. The loan proceeds were used to repay $258 million of notes payable to FirstEnergy, including $9 million of interest and $63 million of bank loans that were scheduled to mature on November 16, 2010. Additional proceeds will be used for general company purposes, including an $11 million repayment of a third-party seller’s note maturing October 29, 2010.
Revolving Credit FacilityFacilities
FirstEnergy has the capability to request an increase in the total commitments available under the $2.75 billion revolving credit facility (included in the borrowing capability table above) up to a maximum of $3.25 billion, subject to the discretion of each lender to provide additional commitments. A total of 25 banks participate in the facility, with no one bank having more than 7.3% of the total commitment. Commitments under the facility are available until August 24, 2012, unless the lenders agree, at the request of the borrowers, to an unlimited number of additional one-year extensions. Generally, borrowings under the facility must be repaid within 364 days. Available amounts for each borrower are subject to a specified sub-limit, as well as applicable regulatory and other limitations.

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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 of September 30, 2010:March 31, 2011:
                
 Revolving Regulatory and  Revolving Regulatory and 
 Credit Facility Other Short-Term  Credit Facility Other Short-Term 
Borrower Sub-Limit Debt Limitations  Sub-Limit Debt Limitations 
 (In millions)  (In millions) 
FirstEnergy $2,750 $—(1) $2,750 $—(1)
FES 1,000  —(1) 1,000  —(1)
OE 500 500  500 500 
Penn 50  34(2) 50  33(2)
CEI  250(3) 500   250(3) 500 
TE  250(3) 500   250(3) 500 
JCP&L 425  410(2) 425  411(2)
Met-Ed 250  300(2) 250  300(2)
Penelec 250  300(2) 250  300(2)
ATSI  50(4) 50   50(4) 50 
(1) No regulatory approvals, statutory or charter limitations applicable.limitations.
 
(2) Excluding amounts that may be borrowed under the regulated companies’ money pool.
 
(3) Borrowing sub-limits for CEI and TE may be increased to up to $500 million by delivering notice to the administrative agent that such borrower has senior unsecured debt ratings of at least BBB by S&P and Baa2 by Moody’s.
 
(4) The borrowing sub-limit for ATSI may be increased up to $100 million by delivering notice to the administrative agent that ATSI has received regulatory approval to have short-term borrowings up to the same amount.
Under the $2.75 billion revolving credit facility, borrowers may request the issuance of LOCs expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit.
The $2.75 billion revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%, measured at the end of each fiscal quarter. As of September 30, 2010,March 31, 2011, FirstEnergy’s and its subsidiaries’ debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:
     
Borrower    
FirstEnergy
60.2%
FES
53.2%
OE
53.1%
Penn
30.8%
CEI
  57.6%
TE
FES		  57.753.3%
JCP&L
OE		  34.455.0%
Met-Ed
Penn		  37.635.0%
Penelec
CEI		  51.856.4%
ATSI
TE		  48.858.1%
JCP&L34.5%
Met-Ed44.3%
Penelec54.5%
ATSI49.6%

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As of September 30, 2010,March 31, 2011, FirstEnergy could issue additional debt of approximately $2.9$7.1 billion, or recognize a reduction in equity of approximately $1.6$3.8 billion, and remain within the limitations of the financial covenants required by its $2.75 billion revolving credit facility.
The $2.75 billion revolving credit facility, does 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 “pricing grids,” whereby the cost of funds borrowed under the facility is related to the credit ratings of the company borrowing the funds.

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In addition to the $2.75 billion revolving credit facility, FirstEnergy also has access to an additional $2.2 billion of revolving credit facilities relating to the Allegheny companies. The following table summarizes the borrowing sub-limits for each borrower under the facilities as of March 31, 2011:
     
  Revolving 
  Credit Facility 
Borrower Sub-Limit 
  (In millions) 
AE $250 
AE Supply  1,000 
MP  110 
PE  150 
WP  200 
AGC  50 
TrAIL  450 
Under the terms of their individual credit facilities, outstanding debt of AE Supply, MP, PE, WP and AGC may not exceed 65% of the sum of their debt and equity as of the last day of each calendar quarter. Outstanding debt for TrAIL may not exceed 70% and 65% of the sum of its debt and equity as of the last day of each calendar quarter through June 30, 2011 and December 31, 2012, respectively. These provisions limit debt levels of these subsidiaries and also limit the net assets of each subsidiary that may be transferred to AE.
FirstEnergy, the Utilities, FES and AESC are currently pursuing an aggregate of up to $4.0 billion in new multi-year revolving credit facilities to replace a portion of the existing facilities described above.
FirstEnergy Money Pools
FirstEnergy’s regulated companies, excluding regulated companies acquired in the Allegheny merger, also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy’s unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first nine monthsquarter of 20102011 was 0.53%0.38% per annum for the regulated companies’ money pool and 0.60%0.47% per annum for the unregulated companies’ money pool. In March 2011, AE Supply invested $200 million into the unregulated money pool. FirstEnergy and its regulated companies acquired in the Allegheny merger have filed with the appropriate regulatory commissions to receive approval to be part of the FirstEnergy regulated money pool.
Pollution Control Revenue Bonds
As of September 30, 2010,March 31, 2011, FirstEnergy’s currently payable long-term debt included approximately $1.3 billion$827 million (FES — $1.2 billion,$778 million, Met-Ed — $29 million and Penelec — $45$20 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 September 30, 2010:March 31, 2011:
                
 Aggregate LOC Reimbursements of Aggregate LOC Reimbursements of
LOC Bank Amount(2) LOC Termination Date LOC Draws Due Amount(1) LOC Termination Date LOC Draws Due
 (In millions)  (In millions) 
CitiBank N.A. $166 June 2014 June 2014 $166 June 2014 June 2014
The Bank of Nova Scotia 284 Beginning April 2011 Multiple dates(3) 178 Beginning June 2012 Multiple dates(2)
The Royal Bank of Scotland 131 June 2012 6 months 131 June 2012 6 months
Wachovia Bank 152 March 2014 March 2014 152 March 2014 March 2014
Barclays Bank(1)
 528 Beginning December 2010 30 days
PNC Bank 70 Beginning November 2010 180 days
US Bank 60 April 2014 6 months
UBS 272 April 2014 April 2014
            
Total $1,331     $959    
            
(1) Supported by 18 participating banks, with no one bank having more than 14% of the total commitment.
(2)Includes approximately $13$10 million of applicable interest coverage.
 
(3)(2) Shorter of 6 months or LOC termination date ($15549 million) and shorter of one year or LOC termination date ($129 million).
On August 20, 2010, FES completed the remarketing of $250 million of PCRBs. Of the $250 million, $235 million of PCRBs were converted from a variable interest rate to a fixed interest rate. The remaining $15 million of PCRBs continue to bear a fixed interest rate. The interest rate conversion minimizes financial risk by converting the long-term debt into a fixed rate and, as a result, reducing exposure to variable interest rates over the short-term. These remarketings included two series: $235 million of PCRBs that now bear a per-annum rate of 2.25% and are subject to mandatory purchase on June 3, 2013; and $15 million of PCRBs that now bear a per-annum rate of 1.5% and are subject to mandatory purchase on June 1, 2011.

 

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On October 1, 2010,March 17, 2011, FES completed the refinancing and remarketing of six series of PCRBs totaling $313 million.$207 million variable rate PCRBs. These PCRBs were converted fromremained in a variable interest mode, supported by bank LOC’s. Also, on March 1, 2011, FES repurchased $50 million of non-LOC backed fixed rate to a fixed long term interest rate of 3.375% per annum and arePCRBs that were subject to mandatory purchase on Julydemand by the owner on that date.
On April 1, 2015. The LOCs for2011, FES completed the refinanced seriesremarketing of an additional $97 million of non-LOC backed commercial paper rate and fixed rate PCRBs totaling $208(including the $50 million terminated asrepurchased on March 1) into variable rate modes with LOC support. Also on April 1, 2011, Penelec completed the remarketing of October 1, 2010. The LOCs for$25 million of non-LOC backed commercial paper rate PCRBs into a variable rate mode with LOC support.
In connection with the remarketed seriesremarketings, approximately $207 aggregate principal amount of FMBs previously delivered to LOC providers were cancelled, and approximately $50 million aggregate principal amount of FMBs delivered to secure PCRBs totaling $108 million will terminatebe cancelled on November 1, 2010.May 31, 2011.
Long-Term Debt Capacity
As of September 30, 2010,March 31, 2011, the Ohio Companies and Penn had the aggregate capability to issue approximately $2.5$2.4 billion of additional FMBs on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMBs by the Ohio Companies is also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMBs) supporting pollution control notes or similar obligations, or as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE and CEI to incur additional secured debt not otherwise permitted by a specified exception of up to $116$118 million and $25$17 million, respectively, as of September 30, 2010.respectively. As a result of theits indenture provisions, TE cannot incur any additional secured debt. Met-Ed and Penelec had the capability to issue secured debt of approximately $380$365 million and $358$346 million, respectively, under provisions of their senior note indentures as of September 30, 2010.March 31, 2011. In addition, based upon their respective FMB indentures, net earnings and available bondable property additions as of March 31, 2011, MP, PE and WP had the capability to issue approximately $685 million of additional FMBs in the aggregate.
Based upon FGCO’s FMB indenture, net earnings and available bondable property additions as of September 30, 2010,March 31, 2011, FGCO had the capability to issue $1.9$2.4 billion of additional FMBs under the terms of that indenture. Based upon NGC’s FMB indenture, net earnings and available bondable property additions, NGC had the capability to issue $294 million$1.2 billion of additional FMBs as of September 30, 2010.March 31, 2011.
FirstEnergy’s access to capital markets and costs of financing are influenced by the ratings of its securities. On February 11, 2010, S&P issued a report lowering FirstEnergy’sMarch 1, 2011, Fitch affirmed the ratings and outlook of FirstEnergy and its subsidiaries’ credit ratings by one notch, while maintaining its stable outlook.subsidiaries. On February 25, 2011, Moody’s and Fitch affirmed the ratings and stable outlook of FirstEnergy and its subsidiaries on February 11, 2010. On September 28, 2010, S&P issued a report reaffirmingregulated utilities, upgraded AE’s senior unsecured ratings to Baa3 from Ba1 and placed the ratings and stable outlook of FirstEnergy and its subsidiaries.for FES under review for possible downgrade. The following table displays FirstEnergy’s FES’ and the Utilities’its subsidiaries’ securities ratings as of September 30, 2010.March 31, 2011.
             
  Senior Secured Senior Unsecured
Issuer S&P Moody’s Fitch S&P Moody’s Fitch
FirstEnergy Corp. — — — BB+ Baa3 BBB
FirstEnergy SolutionsAllegheny———BB+Baa3BBB-
FES — — — BBB- Baa2 BBB
Ohio EdisonAE Supply BBB A3BBB+BBB-Baa2BBB
Pennsylvania PowerBBB+A3BBB+———
Cleveland Electric IlluminatingBBBBaa1 BBB BBB- Baa3 BBB-
Toledo EdisonBBBBaa1BBB———
Jersey Central Power & LightAGC — — — BBB- Baa2BBB+
Metropolitan EdisonBBBA3BBB+Baa3 BBB-Baa2BBB
Pennsylvania ElectricBBBA3BBB+BBB-Baa2BBB
ATSI — — — BBB- Baa1 —
CEIBBBBaa1BBBBBB-Baa3BBB-
JCP&L———BBB-Baa2BBB+
Met-EdBBBA3BBB+BBB-Baa2BBB
MPBBB+Baa1BBB+BBB-Baa3BBB-
OEBBBA3BBB+BBB-Baa2BBB
PenelecBBBA3BBB+BBB-Baa2BBB
PennBBB+A3BBB+———
PEBBB+Baa1BBB+BBB-Baa3BBB-
TEBBBBaa1BBB———
TrAIL———BBB-Baa2BBB
WPBBB+A3BBB+BBB-Baa2BBB-

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Changes in Cash Position
As of September 30, 2010,March 31, 2011, FirstEnergy had $632 million$1.1 billion of cash and cash equivalents compared to $874 million$1 billion as of December 31, 2009.2010. As of September 30, 2010March 31, 2011 and December 31, 2009,2010, FirstEnergy had approximately $14$73 million and $12$13 million, respectively, of restricted cash included in other current assets on the Consolidated Balance Sheet.
During the first ninethree months of 2010,2011, FirstEnergy received $730$240 million of cash dividends from its subsidiaries and paid $503$190 million in cash dividends to common shareholders, including $20 million paid in March by Allegheny to its former shareholders.
Cash Flows From Operating Activities
FirstEnergy’s consolidated net cash from operating activities is provided primarily by its competitive energy services and energy delivery services businesses (see Results of Operations above). Net cash provided from operating activities increaseddecreased by $609$15 million during the first ninethree months of 20102011 compared to the comparable period in 2009,2010, as summarized in the following table:
                        
 Nine Months    Three Months   
 Ended September 30 Increase  Ended March 31 Increase 
Operating Cash Flows 2010 2009 (Decrease)  2011 2010 (Decrease) 
 (In millions)  (In millions) 
Net income $580 $754 $(174) $45 $149 $(104)
Non-cash charges and other adjustments 1,648 1,755  (107) 515 367 148 
Pension trust contribution —  (500) 500   (157) —  (157)
Working Capital and other  (155)  (545) 390 
Working capital and other 88  (10) 98 
              
 $2,073 $1,464 $609  $491 $506 $(15)
              

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The decreaseincrease in non-cash charges and other adjustments is primarily due to lower net amortization of regulatory assets of ($354 million), including the impact of CEI’s $216 million regulatory asset impairment recorded during the first quarter of 2009, a $142 million charge relating to loss on debt redemptions during the third quarter of 2009 and changes inincreased deferred income taxes and investment tax credits of ($162112 million). The decrease, increased asset impairments ($19 million), changes in non-cash chargesaccrued compensation and other adjustments wasretirement benefits ($68 million) and increased depreciation ($27 million), partially offset by impairmentlower amortization of long-lived assets of $294 million, including the impact of the $292 million impairment of certain FGCO facilities and changes in the deferral of new regulatory assets of $136 million.($80 million).
The changeincrease in cash flows from working capital and other is primarily due to cash proceeds of $129 million received on the termination of fixed-for-floating interest rate swaps during the seconddecreased receivables ($162 million), decreased prepayments and third quarters of 2010, changes in investment securities of $133 million, a decrease in prepaidother current assets of $345 million($85 million) and a $250 million increase indecreased materials and supplies ($82 million), partially offset by decreased accrued taxes ($189 million) and decreased accounts receivable.payable ($33 million).
Cash Flows From Financing Activities
In the first ninethree months of 2010,2011, cash used for financing activities was $870$550 million compared to cash provided from financing activities of $617$594 million in the first ninethree months of 2009. The decrease was primarily due to activity during the first nine months of 2009 which included new debt issuances and long-term debt retirements associated with a $1.2 billion senior note tender offer completed by FirstEnergy in September 2009.2010. The following table summarizes security issuances (net of any discounts) and redemptions:
                
 Nine Months  Three Months 
 Ended September 30  Ended March 31 
Securities Issued or Redeemed 2010 2009  2011 2010 
 (In millions)  (In millions) 
New Issues
  
First mortgage bonds — 398 
Pollution control notes 250 859  150 — 
Senior secured notes — 297 
Long-term revolvers 60 — 
Unsecured Notes 1 2,597  7 — 
          
 $251 $4,151  $217 $— 
          
  
Redemptions
  
First mortgage bonds 7 — 
Pollution control notes 251 687   (200) — 
Long-term revolvers  (20) — 
Senior secured notes 63 54   (109) 9 
Unsecured notes 101 1,472   (30) 100 
          
 $422 $2,213  $(359) $109 
          
  
Short-term borrowings, net $(171) $(764) $(214) $(295)
          
On March 29, 2011, FES paid off a $100 million term loan secured by FMBs that was scheduled to mature on March 31, 2011. On April 8, 2011, FirstEnergy entered into a $150 million unsecured term loan with an April 2013 maturity.
In March 2011 FES repurchased and retired $20 million of its 6.80% unsecured senior notes and $10 million of its 6.05% unsecured senior notes originally outstanding in the principal amounts of $500 million and $600 million, respectively. Additionally, on April 29, 2011, Met-Ed redeemed approximately $14 million of FMBs securing PCRBs.
During the remainder of 2011, FirstEnergy and its subsidiaries expect to pursue, from time to time, continued reductions in outstanding long-term debt of up to approximately $1.0 to $1.5 billion including through redemptions, open market or privately negotiated purchases. Any such transactions will be subject to prevailing market conditions, liquidity requirements and other factors.

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Cash Flows From Investing Activities
Net cashCash flows usedreceived from investing activities in investing activitiesthe first three months of 2011 resulted primarily from the cash acquired in the Allegheny merger, partially offset by cash used for property additions. Additions for the energy delivery services segment primarily represent expenditures related to transmission and distribution facilities. Capital spending by the competitive energy services segment is principally generation-related. The following table summarizes investing activities for the first ninethree months of 20102011 and 20092010 by business segment:
                                
Summary of Cash Flows Property        Property       
Provided from (Used for) Investing Activities Additions Investments Other Total  Additions Investments Other Total 
 (In millions)  (In millions) 
Sources (Uses)
  
Nine Months Ended September 30, 2010
 
Energy delivery services $(546) $82 $11 $(453)
Three Months Ended March 31, 2011
 
Regulated distribution $(177) $60 $(9) $(126)
Competitive energy services  (860)  (26)  (53)  (939)  (214)  (15)  (8)  (237)
Regulated independent transmission  (27)  (1) —  (28)
Other  (18)  (3) 34 13   (31) 590 145 704 
Inter-Segment reconciling items  (43)  (23) —  (66) —  (22)  (150)  (172)
                  
Total $(1,467) $30 $(8) $(1,445) $(449) $612 $(22) $141 
                  
  
Nine Months Ended September 30, 2009
 
Energy delivery services $(524) $(121) $(35) $(680)
Three Months Ended March 31, 2010
 
Regulated distribution $(152) $62 $(6) $(96)
Competitive energy services  (893)  (6)  (21)  (920)  (329) —  (1)  (330)
Regulated independent transmission  (14) —  (1)  (15)
Other  (133)  (11)  (144)  (13) — —  (13)
Inter-Segment reconciling items  (25)  (25) 6  (44) —  (22) —  (22)
                  
Total $(1,575) $(152) $(61) $(1,788) $(508) $40 $(8) $(476)
                  

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Net cash used forprovided from investing activities in the first ninethree months of 2010 decreased2011 increased by $343$617 million compared to the first ninethree months of 2009.2010. The decreaseincrease was principally due to cash acquired in the Allegheny merger ($590 million), a $108 million decrease in property additions (principally lower AQC system expenditures) and an increase in cash proceeds from the salepurchases of assets of $98 million, partially offset by $110 million spentcustomer intangibles by FES in the customer acquisition process.process ($100 million) and a decrease in property additions ($59 million), principally due to lower AQC system expenditures, partially offset by decreased proceeds from asset sales ($114 million).
During the remaining quarternine months of 2010,2011, capital requirements for property additions and capital leases are expected to be approximately $410$1.8 billion. This includes approximately $90 million including approximately $32 millionof nuclear fuel expenditures.
CONTRACTUAL OBLIGATIONS
Estimated cash payments for nuclear fuel. These cash requirementscontractual obligations that are expected to be satisfied from a combination of internal cash and short-term credit arrangements.considered firm obligations acquired by FirstEnergy in the AE merger are summarized as follows:
                     
          2012-  2014-    
Contractual Obligations Total  2011  2013  2015  Thereafter 
  (In millions) 
Long-term debt(1)
 $4,776  $8  $1,445  $1,037  $2,286 
Interest on long-term debt(2)
  2,516   240   470   341   1,465 
Fuel and purchased power(3)
  9,781   956   2,160   1,650   5,015 
Capital expenditures  141   117   24   —   — 
Pension funding (4)
  695   124   175   186   210 
                
                     
Total $17,909  $1,445  $4,274  $3,214  $8,976 
                
(1)Does not include payments made and debt issued subsequent to March 31, 2011.
(2)Interest on variable-rate debt is based on interest rates as of March 31, 2011.
(3)Amounts under contract with fixed or minimum quantities are based on estimated annual requirements.
(4)Estimated contributions through 2021 based on current actuarial assumptions.
GUARANTEES AND OTHER ASSURANCES
As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds and LOCs. Some of the guaranteed contracts contain collateral provisions that are contingent upon either FirstEnergy or its subsidiaries’ credit ratings.

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As of September 30, 2010,March 31, 2011, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $3.8 billion, as summarized below:
        
 Maximum  Maximum 
Guarantees and Other Assurances Exposure  Exposure 
 (In millions)  (In millions) 
FirstEnergy Guarantees on Behalf of its Subsidiaries  
Energy and Energy-Related Contracts(1)
 $300  $231 
LOC (long-term debt) —Interest coverage(2)
 6 
FirstEnergy guarantee of OVEC obligations 300  300 
Other(3)
 226 
Other(2)
 228 
      
 832  759 
      
  
Subsidiaries’ Guarantees  
Energy and Energy-Related Contracts 54  158 
LOC (long-term debt) —Interest coverage(2)
 4 
FES’ guarantee of NGC’s nuclear property insurance 70  70 
FES’ guarantee of FGCO’s sale and leaseback obligations 2,413  2,375 
Other 2  18 
      
 2,543  2,621 
      
  
Surety Bonds 84  138 
LOC (long-term debt) — Interest coverage(2)
 3 
LOC (non-debt)(4)(5)
 380 
LOC (non-debt)(3)
 318 
      
 467  456 
      
Total Guarantees and Other Assurances $3,842  $3,836 
      
(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 $1.3 billion is reflected in currently payable long-term debt on FirstEnergy’s consolidated balance sheets.
(3)Includes guarantees of $15 million for nuclear decommissioning funding assurances, $161 million supporting OE’s sale and leaseback arrangement, and $34$37 million for railcar leases.
 
(4)(3) Includes $201$146 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facility.
(5)Includes approximately $135facilities, $130 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $44$42 million pledged in connection with the sale and leaseback of Perry by OE.

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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 guarantees to various providers of credit support for the financing or refinancing by its subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financings where the law might otherwise limit the counterparties’ claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy’s guarantee enables the counterparty’s legal claim to be satisfied by FirstEnergy’s assets. FirstEnergy believes the likelihood is remote that such parental guarantees will increase amounts otherwise paid by FirstEnergy to meet its obligations incurred in connection with ongoing energy and energy-related activities.
While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade to below investment grade, an acceleration or funding obligation or a “material adverse event,” the immediate posting of cash collateral, provision of a LOC or accelerated payments may be required of the subsidiary. As of September 30, 2010,March 31, 2011, FirstEnergy’s maximum exposure under these collateral provisions was $419$557 million, as shown below:
                     
Collateral Provisions FES Utilities Total  FES AE Supply Utilities Total 
 (In millions)  (In millions) 
Credit rating downgrade to below investment grade (1)
 $306 $68 $374  $357 $10 $66 $433 
Material adverse event (2)
 45 — 45  54 57 13 124 
                
Total $351 $68 $419  $411 $67 $79 $557 
                
(1) Includes $85$138 million and $57$46 million that is also considered an acceleration of payment or funding obligation at FES and the Utilities, respectively.
 
(2) Includes $33$53 million that is also considered an acceleration of payment or funding obligation at FES.

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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 $511$623 million, consisting of $463 million due to a below investment grade credit rating, of which $175 million is related to an acceleration of payment or funding obligation, and $48 million due to “material adverse event” contractual clauses.as shown below:
                 
Collateral Provisions FES  AE Supply  Utilities  Total 
  (In millions) 
Credit rating downgrade to below investment grade(1)
 $420  $8  $66  $494 
Material adverse event(2)
  60   56   13   129 
             
Total $480  $64  $79  $623 
             
(1)Includes $138 million and $46 million that is also considered an acceleration of payment or funding obligation at FES and the Utilities, respectively.
(2)Includes $53 million that is also considered an acceleration of payment or funding obligation at FES.
Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $84$138 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.
In addition to guarantees and surety bonds, FES’ contracts entered into by the Competitive Energy Services segment, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions whichthat require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ and AE Supply’s power portfolio as of September 30, 2010,March 31, 2011 and forward prices as of that date, FES hasand AE Supply have posted collateral of $244 million.$158 million and $5 million, respectively. 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 $46 million.$52 million of collateral. Depending on the volume of forward contracts and future price movements, FEShigher amounts for margining could be required to post higher amounts for margining.be posted.
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’ 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 willmay have claims against each of FES, FGCO and NGC, regardless of whether their primary obligor is FES, FGCO or NGC.
On October 22, 2010, Signal Peak and Global Rail entered intoare borrowers under a $350 million syndicated two-year senior secured term loan facility among the two limited liability companies that comprise Signal Peak and Global Rail, as borrowers, Sovereign Bank, CoBank, Credit Agricole, U.S. Bank, BBVA Compass, Royal Bank of Canada, Fifth Third, Comerica Bank, CIBC Inc. and First Merit banks, as lenders, and Union Bank, N.A. as lender, administrative agent, collateral agent and syndication agent.facility. FirstEnergy, together with WMB Loan Ventures LLC and WMB Loan Ventures II LLC, the entities that share ownership with FEV in the borrowers with FEV, have provided a guaranty of the borrowers’ obligations under the facility. In addition, FEV and the other entities that directly own the equity interestsinterest in the borrowers have pledged those interests to the bankslenders under the term loan facility as collateral for the facility.

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OFF-BALANCE SHEET ARRANGEMENTS
FES and the Ohio Companies have obligations that are not included on their Consolidated Balance Sheets related to sale and leaseback arrangements involving the Bruce Mansfield Plant, Perry Unit 1 and Beaver Valley Unit 2, which are satisfied through operating lease payments. The total present value of these sale and leaseback operating lease commitments, net of trust investments, is $1.7 billion as of September 30, 2010.
March 31, 2011.
MARKET RISK INFORMATION
FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.
Commodity Price Risk
FirstEnergy is exposed to financial and market risks resulting from the fluctuation offluctuating interest rates and commodity prices, associated withincluding prices for electricity, energy transmission, natural gas, coal nuclear fuel and emission allowances.energy transmission. To manage the volatility relating to these exposures, FirstEnergy established a Risk Policy Committee, comprised of members of senior management, which provides general management oversight for risk management activities throughout FirstEnergy. The Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. FirstEnergy uses a variety of non-derivative and derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps. TheIn addition to derivatives, are used principally for hedging purposes.FirstEnergy also enters into master netting agreements with certain third parties.

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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 56 to the consolidated financial statements). Sources of information for the valuation of commodity derivative contracts as of September 30, 2010March 31, 2011 are summarized by year in the following table:
                                                        
Source of Information-                              
Fair Value by Contract Year 2010 2011 2012 2013 2014 Thereafter Total  2011 2012 2013 2014 2015 Thereafter Total 
 (In millions)  (In millions) 
Prices actively quoted(1)
 $(2) $— $— $— $— $— $(2) $— $— $— $— $— $— $— 
Other external sources(2)
  (328)  (369)  (164)  (53) 7  (10)  (917)  (315)  (152)  (44)  (36) — —  (547)
Prices based on models — — — —  (9) 141 132   (11) — — — 19 106 114 
                              
Total(3)
 $(330) $(369) $(164) $(53) $(2) $131 $(787) $(326) $(152) $(44) $(36) $19 $106 $(433)
                              
(1) Represents exchange traded New York Mercantile Exchange futures and options.
 
(2) Primarily represents contracts based on broker and IntercontinentalExchange quotes.
 
(3) Includes $629$366 million in non-hedge commodity derivative contracts that are primarily related to NUG contracts. NUG contracts are generally 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 September 30, 2010,March 31, 2011, an adverse 10% change in commodity prices would decrease net income by approximately $6$12 million ($47 million net of tax) during the next 12 months.
Interest Rate Swap Agreements — 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 portfolio of its subsidiaries. These derivatives 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 September 30, 2010, no fixed-for-floating interest rate swap agreements were outstanding.
Total unamortized gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements totaled $129 million ($84 million net of tax) as of September 30, 2010. 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 $5 million and $7 million for the three and nine months ended September 30, 2010.
Equity Price Risk
FirstEnergy provides a noncontributory qualified defined benefit pension plan that covers substantially all of its employees other than Allegheny employees employed by FirstEnergy and non-qualified pension plans that cover certain employees.employees (the FirstEnergy Pension Plan). In addition, effective on the date of the merger, FirstEnergy provides noncontributory qualified defined pension plan benefits that cover substantially all of Allegheny employees employed by FirstEnergy and a supplemental executive retirement plan that covers certain Allegheny executives employed by FirstEnergy (the Allegheny Pension Plan). The plan providesFirstEnergy Pension Plan and the Allegheny Pension Plan provide defined benefits based on years of service and compensation levels.
Eligible FirstEnergy also provides health care benefits (which include certain employee contributions, deductibles and co-payments) upon retirement to employees hired prior to January 1, 2005,retirees, their dependents and, under certain circumstances, their survivors. survivors are provided other postretirement benefits such as a minimum amount of noncontributory life insurance, optional contributory insurance and certain health care benefits. These other postretirement benefits are not provided in retirement for employees hired on or after January 1, 2005.
Eligible Allegheny retirees and dependents are provided other postretirement benefits such as subsidies for medical and life insurance plans. Subsidized medical coverage is not provided in retirement to Allegheny employees employed by FirstEnergy that were hired on or after January 1, 1993, with the exception of certain union employees who were hired or became members before May 1, 2006.
The benefit plan assets and obligations are remeasured annually using a December 31 measurement date or as significant triggering events occur. As of September 30, 2010, approximately 44% ofMarch 31, 2011, the FirstEnergy pension plan assets arewas invested in approximately 32% of equity securities, and 56% are invested in47% of fixed income securities.securities, 10% of absolute return strategies, 5% of real estate, 2% of private equity and 4% of cash. The plan is 81%FirstEnergy Pension Plan and the Allegheny Pension Plan were 86% and 78%, respectively, funded on an accumulated benefit obligation basis as of September 30, 2010.March 31, 2011. A decline in the value of FirstEnergy’s 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 the first quarter of 2011, FirstEnergy currently estimates thatmade a $157 million contribution to its qualified pension plans. FirstEnergy intends to make additional cash contributions will be required beginningof $220 million and $6 million to its qualified pension plans and postretirement benefit plans, respectively, in 2012.the last three quarters of 2011.

 

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Nuclear decommissioning trust funds have been established to satisfy NGC’s and the Utilities’ nuclear decommissioning obligations. As of September 30, 2010,March 31, 2011, approximately 15%85% of the funds were invested in fixed income securities, 9% of the funds were invested in equity securities and 85%6% were invested in fixed income securities,short-term investments, with limitations related to concentration and investment grade ratings. The equity securitiesinvestments are carried at their market valuevalues of approximately $305$1,741 million, $194 million and $115 million for fixed income securities, equity securities and short-term investments, respectively, as of September 30, 2010.Mach 31, 2011, excluding $(31) million of receivables, payables, deferred taxes and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $31$19 million reduction in fair value as of September 30, 2010.March 31, 2011. The decommissioning trusts of JCP&L and the Pennsylvania Companies are subject to regulatory accounting, with unrealized gains and losses recorded as regulatory assets or liabilities, since the difference between investments held in trust and the decommissioning liabilities will be recovered from or refunded to customers. NGC, OE and TE recognize in earnings the unrealized losses on available-for-sale securities held in their nuclear decommissioning trusts as other-than-temporary impairments. A decline in the value of FirstEnergy’s nuclear decommissioning trusts or a significant escalation in estimated decommissioning costs could result in additional funding requirements. In the first three months of 2011, approximately $1 million was contributed to JCP&L’s nuclear decommissioning trusts. During 2010,the second quarter of 2011, FirstEnergy intends to contribute approximately $4 million was contributedand $1 million to the OE and TE nuclear decommissioning trusts, respectively, to comply with requirements under certain sale-leaseback transactions in which OE and TE continue as lessees, and $4 million was contributedlessees. On March 28, 2011, FENOC submitted its biennial report on nuclear decommissioning funding to the JCP&L and PennsylvaniaNRC. This submittal identified a total shortfall in nuclear decommissioning trustsfunding for Beaver Valley Unit 1 and Perry of approximately $93 million. This estimate encompasses the shortfall covered by the existing $15 million parental guarantee. FENOC agreed to comply with regulatory requirements. FirstEnergy continuesincrease the parental guarantee to evaluate$95 million within 90 days of the status of its funding obligations for the decommissioning of these nuclear facilities and does not expect to make additional cash contributions to the nuclear decommissioning trusts for the remainder of 2010 other than those to the JCP&L and Pennsylvania Companies’ nuclear decommissioning trusts due to regulatory requirements.submittal.
CREDIT RISK
Credit risk is the risk of an obligor’s failure to meet the terms of any investment contract, loan agreement or otherwise perform as agreed. Credit risk arises from all activities in which success depends on issuer, borrower or counterparty performance, whether reflected on or off the balance sheet. FirstEnergy engages in transactions for the purchase and sale of commodities including gas, electricity, coal and emission allowances. These transactions are often with major energy companies within the industry.
FirstEnergy maintains credit policies with respect to its counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of its credit program, FirstEnergy aggressively manages the quality of its portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB (S&P). As of September 30, 2010,March 31, 2011, the largest credit concentration was with J.P. Morgan Chase & Co., which is currently rated investment grade, representing 9.42%13.4% of FirstEnergy’s total approved credit risk.
risk comprised of 5.9% for FES, 2.1% for JCP&L, 2.7% for Met-Ed and a combined 2.7% for OE, TE and CEI.
OUTLOOK
Reliability Initiatives
Federally-enforceable mandatory reliability standards apply to the bulk powerelectric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES, FGCO, FENOC, and ATSI.ATSI and TrAIL Company. The NERC, as the ERO is charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including ReliabilityFirstCorporation. All of FirstEnergy’s facilities are located within the ReliabilityFirstregion. FirstEnergy actively participates in the NERC and ReliabilityFirststakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by the ReliabilityFirstCorporation.
FirstEnergy believes that it generally is in compliance with all currently-effective and enforceable reliability standards. FirstEnergy’s practice is to address and resolve any occasional or isolated incidents of noncompliance as they ariseNevertheless, in the normal course of operations.operating its extensive electric utility systems and facilities, FirstEnergy also believesoccasionally 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 ReliabilityFirst. Moreover, it is clear that the NERC, ReliabilityFirstand the FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with new or amended standards cannot be determined at this time; however, 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.
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, that the NERC may take with respect to this matter.

 

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On August 23, 2010, FirstEnergy self-reported to ReliabilityFirsta vegetation encroachment event on a Met-Ed 230 kV line to ReliabilityFirst.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, ReliabilityFirstissued a Notice of Enforcement to investigate the incident. FirstEnergy submitted a data response to ReliabilityFirston September 27, 2010. In March 2011, ReliabilityFirstsubmitted its proposed findings and settlement. At this time, FirstEnergy is evaluating ReliabilityFirst’s proposal and is unable to predict the final outcome of this investigation.
Allegheny has been subject to routine audits with respect to its compliance with applicable reliability standards and has settled certain related issues. In addition, ReliabilityFirstis currently conducting certain violation investigations with regard to matters of compliance by Allegheny.
OhioMaryland
In 1999, Maryland adopted electric industry restructuring legislation, which gave PE’s Maryland retail electric customers the right to choose their electricity generation suppliers. PE remained obligated to provide standard offer generation service (SOS) at capped rates to residential and non-residential customers for various periods. The Ohio Companies operate under an Amended ESP, which expireslongest such period, for residential customers, expired on MayDecember 31, 2011,2008. PE implemented a rate stabilization plan in 2007 that was designed to transition customers from capped generation rates to rates based on market prices and providesthat concluded on December 31, 2010. PE’s transmission and distribution rates for generation supplied throughall customers are subject to traditional regulated utility ratemaking (i.e., cost-based rates).
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 CBP.reasonable profit, was extended indefinitely. The Amended ESPlegislation also allowsestablished a five-year cycle (to begin in 2008) for the Ohio CompaniesMDPSC to collectreport to the legislature on the status of SOS. In August 2007, PE filed a delivery service improvement rider (Rider DSI) at an overall average rate of $0.002 per KWHplan for seeking bids to serve its Maryland residential load for the period after the expiration of April 1, 2009 through December 31, 2011.rate caps. The Ohio Companies currently purchase generation atMDPSC approved the average wholesale rate ofplan and PE now conducts rolling auctions to procure the power supply necessary to serve its customer load. However, the terms on which PE will provide SOS to residential customers after the settlement beyond 2012 will depend on developments with respect to SOS in Maryland between now and then, including but not limited to possible MDPSC decisions in the proceedings discussed below.
The MDPSC opened a CBP conductednew docket in May 2009. FES is oneAugust 2007 to consider matters relating to possible “managed portfolio” approaches to SOS and other matters. “Phase II” of the supplierscase 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 and other SOS-related pending proceedings discussed below.
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 Ohio Companies throughelectricity market in Maryland as a “failure” and urged the May 2009 CBP. The PUCO approved a $136.6 million distribution rate increase forMDPSC to use its existing authority to order the Ohio Companiesconstruction of new generation in January 2009, which went into effect on January 23, 2009 for OE ($68.9 million)Maryland, vary the means used by utilities to procure generation and TE ($38.5 million) and on May 1, 2009 for CEI ($29.2 million). Applications for rehearing of the PUCO orderinclude more renewables in the distribution case were filed by the Ohio Companies and one other party. The Ohio Companies raised numerous issues in their application for rehearing related to rate recovery of certain expenses, recovery of line extension costs, the level of rate of return and the amount of general plant balances. The PUCO has not yet issued a substantive Entry on Rehearing.
On October 20, 2009, the Ohio Companies filed an MRO to procure, through a CBP, generation supply for customers who do not shop with an alternative supplier for the period beginning June 1, 2011. The CBP would be similar, in all material respects, to the CBP conducted in May 2009 in that it would procure energy, capacity and certain transmission services on a slice of system basis. However, unlike the May 2009 CBP, the MRO would include multiple bidding sessions and multiple products with different delivery periods for generation supply designed to reduce potential volatility and supplier risk and encourage bidder participation. Although the Ohio Companies requested a PUCO determination by January 18, 2010, on February 3,mix. In August 2010, the PUCO announced that its determination would be delayed. The PUCO has not yetMDPSC opened another new proceeding to solicit comments on the PJM RPM process. Public hearings on the comments were held in October 2010. In December 2010, the MDPSC issued an order soliciting comments on a model request for proposal for solicitation of long-term energy commitments by Maryland electric utilities. PE and numerous other parties filed comments, and at this time no further proceedings have been set by the MDPSC in this matter.
On March 23, 2010,In September 2007, the Ohio CompaniesMDPSC issued an order that required the Maryland utilities to file detailed plans for how they will meet the “EmPOWER Maryland” proposal that, in Maryland, electric consumption be reduced by 10% and electricity demand be reduced by 15%, in each case by 2015. In October 2007, PE filed an applicationits initial report on energy efficiency, conservation and demand reduction plans in connection with this order. The MDPSC conducted hearings on PE’s and other utilities’ plans in November 2007 and May 2008.
In a related development, 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 new ESP.customer education program, and a pilot deployment of Advanced Utility Infrastructure (AUI) that Allegheny had previously tested in West Virginia. The new ESP will go into effect on June 1, 2011 and conclude on May 31, 2014. Attached toMDPSC ultimately approved the application was a Stipulation and Recommendation signedprograms in August 2009 after certain modifications had been made as required by the Ohio Companies,MDPSC, and approved cost recovery for the programs in October 2009. Expenditures were estimated to be approximately $101 million and would be recovered over the following six years. The AUI pilot was placed on a separate track to be re-examined after further discussion with the Staff of the PUCO,MDPSC and an additional fourteen parties signing as Signatory Parties, with two additional parties agreeing not to oppose the adoption of the Stipulation. The material terms of the Stipulation include a CBP similar to the one used in May 2009 and the one proposed in the October 2009 MRO filing; a 6% generation discount to certain low-income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (initial auctions scheduled for October 20, 2010 and January 25, 2011); no increase in base distribution rates through May 31, 2014; load cap of no less than 80%, which also applies to any tranches assigned post auction; and a new distribution rider, Delivery Capital Recovery Rider (Rider DCR), to recover a return of, and on, capital investments in the delivery system. This Rider substitutes for Rider DSI which terminates by its own terms. The Ohio Companies also agree not to collect certain amounts associated with RTEP and administrative costs associatedother stakeholders. Meanwhile, extensive meetings with the moveMDPSC Staff and other stakeholders to PJM, dependent on the outcomediscuss details of certain PJM proceedings. Many of the existing riders approved in the previous ESP remain in effect, some with modifications. The new ESP also requests the resolution of current proceedings pending at the PUCO regarding corporate separation, elements of the smart grid proceedingPE’s plans for additional and the move to PJM. FirstEnergy recorded approximately $39.5 million of regulatory asset impairments and expenses related to the ESP. On May 12, 2010, a supplemental stipulation was filed that added two additional parties to the Stipulation, namely the City of Akron, Ohio and Council for Smaller Enterprises, to provide additional energy efficiency benefits. On July 22, 2010, a second supplemental stipulation was filed that, among other provisions provides a commitment that retail customers of the Ohio Companies will not pay certain costs related to the companies’ integration into PJM,improved programs for the longer of the five year period from June 1, 2011 through May 31, 2016 or when the amount of costs avoided by customers for certain types of products totals $360 million dependent on the outcome of certain PJM proceedings, and establishes a $12 million fund to assist low income customers over the term of the ESP. Additional parties signing or not opposing the second supplemental stipulation include Northeast Ohio Public Energy Council (NOPEC), Northwest Ohio Aggregation Coalition (NOAC), Environmental Law and Policy Center and a number of low income community agencies. The PUCO modified and approved the new ESP on August 25, 2010. The Companies accepted the PUCO’s decision subject to the implementation of certain elements of the ESP being consistent with the terms as they were included2012-2014 began in the stipulation. On September 24, 2010, an application for rehearing was filed by the OCC and two other parties. The Ohio Companies and other parties filed their memorandum contra to that application for rehearing on October 4, 2010. The PUCO granted the application for rehearing on October 22, 2010. The PUCO has yet to rule on the substance of the application for rehearing.
Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total annual energy savings equivalent of approximately 166,000 MWH in 2009, 290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in 2012 and 530,000 MWH in 2013, with additional savings required through 2025. Utilities are also required to reduce peak demand in 2009 by 1%, with an additional 0.75% reduction each year thereafter through 2018. The Ohio Companies filed an application with the PUCO seeking amendments to these benchmarks. On January 7, 2010, the PUCO amended the Ohio Companies’ 2009 energy efficiency benchmarks to zero, contingent upon the Ohio Companies meeting the revised benchmarks in a period of not more than three years. On March 10, 2010, the PUCO found that the Ohio Companies’ peak demand reduction programs complied with PUCO rules.April 2011.

 

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On December 15,In March 2009, the Ohio CompaniesMaryland PSC issued an order suspending until further notice 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. PE and several other utilities filed requests for reconsideration of various parts of the requiredorder, which were denied. The MDPSC is continuing to conduct hearings and collect data on payment plan and related issues and has adopted a set of proposed regulations that expand the summer and winter “severe weather” termination moratoria when temperatures are very high or very low, from one day, as provided by statute, to 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. days on each occurrence.
On March 8, 2010,24, 2011, the Ohio CompaniesMDPSC held an initial hearing to discuss possible new regulations relating to service interruptions, storm response, call center metrics, and related reliability standards. The proposed rules included provisions for civil penalties for non-compliance. Numerous parties filed their 2009 Status Update Reportcomments on the proposed rules and participated in the hearing, with many noting issues of cost and practicality relating to implementation. Concurrently, the PUCOMaryland legislature is considering a bill addressing the same topics. The final bill passed on April 11, 2011, 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 MDPSC is directed to consider cost-effectiveness, and may adopt different standards for different utilities based on such factors as system design and existing infrastructure, geography, and customer density. Beginning in which they indicatedJuly 2013, the MDPSC is to assess each utility’s compliance with the 2009 statutory energy efficiencystandards, and peak demand benchmarks as those benchmarks were amended as described above.may assess penalties of up to $25,000 per day per violation. The Ohio Companies expectMDPSC has ordered that all costs associated with compliance will be recoverable from customers. The Ohio Companies’ three year portfolio plan is still awaiting decision froma working group of utilities, regulators, and other interested stakeholders meet to address the PUCO. The plan has yet to be approved by the PUCO, which is delaying the launchtopics of the programs described in the plan. Without such approval, the Ohio Companies’ compliance with 2010 benchmarks is jeopardized and if not approved soon may require the Ohio Companies to seek an amendment to their annual benchmark requirements for 2010. Failure to comply with the benchmarks or to obtain such an amendment may subject the Companies to an assessment by the PUCO of a forfeiture.proposed rules.
Additionally under SB221, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they served in 2009. In August and OctoberDecember 2009, the Ohio Companies conducted RFPs to secure RECs. The RFPs sought RECs, including solar RECs and RECs generated in Ohio in order to meet the Ohio Companies’ alternative energy requirements as set forth in SB221 for 2009, 2010 and 2011. The RECs acquired through these two RFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. On March 10, 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market. The PUCO reduced the Ohio Companies’ aggregate 2009 benchmark to the level of solar RECs the Ohio Companies acquired through their 2009 RFP processes, provided the Ohio Companies’ 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC benchmark. On April 15, 2010, the Ohio Companies and FES (due to its status as an electric service company in Ohio) filed compliance reports with the PUCO setting forth how they individually satisfied the alternative energy requirements in SB221 for 2009. FES also applied for a force majeure determination from the PUCO regarding a portion of their compliance with the 2009 solar energy resource benchmark, which application is still pending. In July 2010, the Ohio Companies initiated an additional RFP to secure RECs and solar RECs needed to meet the Ohio Companies’ alternative energy requirements as set forth in SB221. As a result of this RFP, contracts were executed in August 2010.
On February 12, 2010, OE and CEIPE filed an application with the PUCOMDPSC for authorization to establish a new credit for all-electric customers. On March 3, 2010,construct the PUCO ordered that rates for the affected customers be set at a level that will provide bill impacts commensurate with charges in place on December 31, 2008 and authorized the Ohio Companies to defer incurred costs equivalent to the difference between what the affected customers would have paid under previously existing rates and what they pay with the new credit in place. Tariffs implementing this new credit went into effect on March 17, 2010. On April 15, 2010, the PUCO issued a Second Entry on Rehearing that expanded the group of customers to which the new credit would apply and authorized deferral for the associated additional amounts. The PUCO also stated that it expected that the new credit would remain in place through at least the 2011 winter season, and charged its staff to work with parties to seek a long term solution to the issue. Tariffs implementing this newly expanded credit went into effect on May 21, 2010. The Ohio Companies also filed on May 14, 2010 an application for rehearingMaryland portions of the Second Entry on Rehearing,PATH Project to be owned by PATH Allegheny Maryland Transmission Company, LLC, which was granted for purposes of further consideration on June 9, 2010. On September 9, 2010, the OCC filed a motion requesting that a procedural schedule be established. The Ohio Companies filed their motion contra on September 23, 2010. The PUCO Staff issued a report related to the all-electric issue on September 24, 2010, in which it provides background on the issueis owned by Potomac Edison and sets forth its bill impact analysis under a number of different scenarios for a longer term solution, but it made no specific recommendation to the PUCO.
Pennsylvania
Met-Ed and Penelec purchase a portion of their POLR 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 POLR and default service obligations.
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, with 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, reflecting the settlement on all but 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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PATH-Allegheny. On February 8, 2010, Penn filed a Petition for Approval of28, 2011, PE withdrew its Default Service Plan for the period June 1, 2011 through May 31, 2013. On July 29, 2010, the parties to the proceeding filed a Joint Petition for Settlement of all issues. The PPUC adopted a Motion approving the Joint Petition for Settlement on October 21, 2010. The Joint Petition resolves all issues relating to Penn’s Default Service Plan for the next program period, including its procurement method, compliance with the Alternative Energy Portfolio Standards Act, rate design and retail market issues. The PPUC’s approval of the Joint Petition is conditioned by holding that the provision relating to the recovery of MISO exit cost fees and one-time PJM integration costs (resulting from Penn’s June 1, 2011 exit of MISO and integration into PJM) be approved, but made subject to the approval of cost recovery by FERC. Penn may not put these provisions into effect until FERC has approved the recovery and allocation of MISO exit fees and PJM integration costs. An Order consistent with the Motion is expected to be enteredapplication. See “Transmission Expansion” in the near future.
The PPUC adopted a Motion on January 28, 2010Federal Regulation and subsequently entered an Order on March 3, 2010 which denies the recovery of marginal transmission losses through the TSC riderRate Matters section for the period of June 1, 2007 through March 31, 2008, and directs Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructs Met-Ed and Penelec to work with the various intervening parties to file a recommendation to the PPUC regarding the establishment of a separate account for all marginal transmission losses collected from ratepayers plus interest to be used to mitigate future generation rate increases beginning January 1, 2011. On March 18, 2010, Met-Ed and Penelec filed a Petition with the PPUC requesting that it stay the portion of the March 3, 2010 Order requiring the filing of tariff supplements to end collection of costs for marginal transmission losses. By Order entered March 25, 2010, the PPUC granted the requested stay until December 31, 2010. Pursuant to the PPUC’s order, Met-Ed and Penelec filed the plan to establish separate accounts for marginal transmission loss revenues and related interest and carrying charges and the plan for the use of these funds to mitigate future generation rate increases commencing January 1, 2011. The PPUC approved this plan on June 7, 2010. On April 1, 2010, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania appealing the PPUC’s March 3, 2010 Order. Although the ultimate outcomefurther discussion of this matter cannot be determined at this time, it is the belief of Met-Ed and Penelec that they should prevail in the appeal and therefore expect to fully recover the approximately $199.7 million ($158.5 million for Met-Ed and $41.2 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011. On July 9, 2010, Met-Ed and Penelec filed their briefs with the Commonwealth Court of Pennsylvania. The Office of Small Business Advocate filed its brief on July 9, 2010. On August 24, 2010, the PPUC as well as MEIUG and PICA filed their briefs. Met-Ed and Penelec filed their reply brief on September 9, 2010.matter.
On May 20, 2010, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider for the period June 1, 2010 through December 31, 2010 including marginal transmission losses as approved by the PPUC, although the recovery of marginal losses will be subject to the outcome of the proceeding related to the 2008 TSC filing as described above. The TSC for Met-Ed’s customers was increased to provide for full recovery by December 31, 2010.
Act 129 was enacted in 2008 to address issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters; and alternative energy. Among other things, Act 129 required utilities to file with the PPUC an energy efficiency and peak load reduction plan, or EE&C Plan, by July 1, 2009, setting forth the utilities’ plans to reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of 4.5% by May 31, 2013. The PPUC entered an Order on February 26, 2010 approving the Pennsylvania Companies’ EE&C Plans and the tariff rider with rates effective March 1, 2010.
Met-Ed, Penelec and Penn jointly filed a Smart Meter Technology Procurement and Installation Plan with the PPUC. This plan proposes a 24-month assessment period in which the Pennsylvania Companies will assess their needs, select the necessary technology, secure vendors, train personnel, install and test support equipment, and establish a cost effective and strategic deployment schedule, which currently is expected to be completed in fifteen years. Met-Ed, Penelec and Penn estimate assessment period costs at approximately $29.5 million, which the Pennsylvania Companies, in their plan, proposed to recover through an automatic adjustment clause. The ALJ’s Initial Decision approved the Smart Meter Plan as modified by the ALJ, including: ensuring that the smart meters to be deployed include the capabilities listed in the PPUC’s Implementation Order; eliminating the provision of interest in the 1307(e) reconciliation; providing for the recovery of reasonable and prudent costs minus resulting savings from installation and use of smart meters; and reflecting that administrative start-up costs be expensed and the costs incurred for research and development in the assessment period be capitalized. On April 15, 2010, the PPUC adopted a Motion by Chairman Cawley that modified the ALJ’s initial decision, and decided various issues regarding the Smart Meter Implementation Plan for the Pennsylvania Companies. The PPUC entered its Order on June 9, 2010, consistent with the Chairman’s Motion. On June 24, 2010, Met-Ed, Penelec and Penn filed a Petition for Reconsideration of a single portion of the PPUC’s Order regarding the future ability to include smart meter costs in base rates. On August 5, 2010, the PPUC granted in part the petition for reconsideration by deleting language from its original order that would have precluded Met-Ed, Penelec and Penn from seeking to include smart meter costs in base rates at a later time.
By Tentative Order entered September 17, 2009, the PPUC provided for an additional 30-day comment period on whether the 1998 Restructuring Settlement 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 above accounting method utilized by Met-Ed and Penelec. Met-Ed and Penelec are awaiting further action by the PPUC.

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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 NUGCNUG rates and market sales of NUG energy and capacity. As of September 30, 2010,March 31, 2011, the accumulated deferred cost balance was a credit of approximately $3$102 million. To better align the recovery of expected costs, onin July 26, 2010, JCP&L filed a request to decrease the amount recovered for the costs incurred under the NUG agreements by $180 million annually. Ifannually, which the NJBPU approved, as filed,allowing the change would not go into effect until Januaryin rates to become effective March 1, 2011.
In accordance with an April 28, 2004 NJBPU order,March 2009 and again in February 2010, JCP&L filed testimony on June 7, 2004, supporting continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The DPA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. JCP&L responded to additional NJBPU staff discovery requests in May and November 2007 and also submitted comments in the proceeding in November 2007. A schedule for further NJBPU proceedings has not yet been set. On March 13, 2009, JCP&L filed its annual SBC PetitionPetitions with the NJBPU that includesincluded a request for a reduction in therequested zero level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009 estimated at $736 million (in 2003 dollars). This matter isBoth matters are currently pending before the NJBPU.
New Jersey statutes requireOhio
The Ohio Companies operate under an ESP, which expires on May 31, 2011, that provides for generation supplied through a CBP. The ESP also allows the state periodically undertakeOhio Companies to collect a planning process, known asdelivery service improvement rider (Rider DSI) at an overall average rate of $0.002 per KWH for the EMP, to address energy related issues including energy security, economic growth, and environmental impact.period of April 1, 2009 through December 31, 2011. The NJBPU adopted an order establishingOhio Companies currently purchase generation at the general process and contentsaverage wholesale rate of specific EMP plans that must be filed by New Jersey electric and gas utilitiesa CBP conducted in order to achieve the goalsMay 2009. FES is one of the EMP. On April 16,suppliers to the Ohio Companies through the May 2009 CBP. The PUCO approved a $136.6 million distribution rate increase for the Ohio Companies in January 2009, which went into effect on January 23, 2009 for OE ($68.9 million) and TE ($38.5 million) and on May 1, 2009 for CEI ($29.2 million).
In March 2010, the NJBPU issuedOhio Companies filed an order indefinitely suspendingapplication for a new ESP, which the requirement of New Jersey utilities to submit Utility Master Plans until such time as the statusPUCO approved in August 2010, with certain modifications. The new ESP will go into effect on June 1, 2011 and conclude on May 31, 2014. The material terms of the EMP has been made clear. At this time, FirstEnergynew ESP include: a CBP similar to the one used in May 2009 and JCP&L cannot determine the impact, if any,one proposed on the EMP may haveOctober 2009 MRO filing (initial auctions held on their operations.
In supportOctober 20, 2010 and January 25, 2011); a load cap of former New Jersey Governor Corzine’s Economic Assistanceno less than 80%, which also applies to tranches assigned post-auction; a 6% generation discount to certain low income customers provided by the Ohio Companies through a bilateral wholesale contract with FES; no increase in base distribution rates through May 31, 2014; and a new distribution rider, Delivery Capital Recovery Plan, JCP&L announcedRider (Rider DCR), to recover a proposalreturn of, and on, capital investments in the delivery system. Rider DCR substitutes for Rider DSI which terminates under the current ESP. The Ohio Companies also agreed not to spend approximately $98recover from retail customers certain costs related to the companies’ 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 million dependent on infrastructurethe outcome of certain PJM proceedings, agreed to establish a $12 million fund to assist low income customers over the term of the ESP and agreed to additional matters related to energy efficiency projectsand alternative energy requirements. Many of the existing riders approved in 2009. the previous ESP remain in effect, with some modifications. The new ESP resolved proceedings pending at the PUCO regarding corporate separation, elements of the smart grid proceeding and expenses related to the ESP.

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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 onprovisions of SB221, the Ohio Companies are required to implement energy efficiency programs that would complementwill achieve a total annual energy savings equivalent to approximately 166,000 MWH in 2009, 290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in 2012 and 530,000 MWH in 2013, with additional savings required through 2025. Utilities are also required to reduce peak demand in 2009 by 1%, with an additional 0.75% reduction each year thereafter through 2018.
In December 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 Ohio Companies expect that all costs associated with compliance will be recoverable from customers. The PUCO issued an Opinion and Order generally approving the Ohio Companies’ 3-year plan, and the Companies are in the process of implementing those currently being offered. The project relating to expansionprograms included in the Plan. Because of the delay in issuing the Order, the launch of the programs included in the plan for 2010 was delayed and will launch during the second quarter of this year. As a result, OE fell short of its statutory 2010 energy efficiency and peak demand reduction benchmarks. 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 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 these them into compliance with their yet-to-be-defined modified benchmarks. Failure to comply with the benchmarks or to obtain such an amendment may subject the Companies to an assessment by the PUCO of a penalty. In addition to approving the programs included in the plan, with only minor modifications, the PUCO authorized the 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 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.
Additionally under SB221, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they served in 2009. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RFPs sought RECs, including solar RECs and RECs generated in Ohio in order to meet the Ohio Companies’ alternative energy requirements as set forth in SB221 for 2009, 2010 and 2011. The RECs acquired through these two RFPs 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. The PUCO reduced the Ohio Companies’ aggregate 2009 benchmark to the level of solar RECs the Ohio Companies acquired through their 2009 RFP processes, provided the Ohio Companies’ 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC benchmark. FES also applied for a force majeure determination from the PUCO regarding a portion of their compliance with the 2009 solar energy resource benchmark. On February 23, 2011, the PUCO granted FES’ force majeure request for 2009 and increased its 2010 benchmark by the amount of SRECs that FES was short of in its 2009 benchmark. In July 2010, the Ohio Companies initiated an additional RFP to secure RECs and solar RECs needed to meet the Ohio Companies’ alternative energy requirements as set forth in SB221 for 2010 and 2011 and executed related contracts in August 2010. 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. The PUCO has not yet acted on that application.
In February 2010, OE and CEI filed an application with the PUCO to establish a new credit for all-electric customers. In March 2010, the PUCO ordered that rates for the affected customers be set at a level that will provide bill impacts commensurate with charges in place on December 31, 2008 and authorized the Ohio Companies to defer incurred costs equivalent to the difference between what the affected customers would have paid under previously existing demand response programsrates and what they pay with the new credit in place. Tariffs implementing this new credit went into effect in March 2010. In April 2010, the PUCO issued a Second Entry on Rehearing that expanded the group of customers to which the new credit would apply and authorized deferral for the associated additional amounts. The PUCO also stated that it expected that the new credit would remain in place through at least the 2011 winter season, and charged its staff to work with parties to seek a long term solution to the issue. Tariffs implementing this newly expanded credit went into effect in May 2010 and the proceeding remains open. The hearing on the matter was held in February 2011. The matter has now been briefed and the Ohio Companies await the PUCO’s decision.

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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 ratepayers 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 and for the use of these funds to mitigate future generation rate increases which the PPUC approved. 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. The argument before the Commonwealth Court, en banc, was held in December 2010. Although the ultimate outcome of this matter cannot be determined at this time, Met-Ed and Penelec believe that they should prevail in the appeal and therefore expect to fully recover the approximately $252.7 million ($188.0 million for Met-Ed and $64.7 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011.
In May 2008, May 2009 and May 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 NJBPU onPPUC, 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.
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 through a prudent mix of long-term, short-term and spot market generation supply with a staggered procurement schedule that varies by customer class, using a descending clock auction. In August 19, 2009, the parties to the proceeding filed a settlement agreement of all but two issues, and implementationthe PPUC entered an Order approving the settlement and the generation procurement plan in November 2009. Generation procurement began in 2009.January 2010.
In February 2010, Penn filed a Petition for Approval of its Default Service Plan for the project relatedperiod 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 programs intendedand peak load reduction; generation procurement; time-of-use rates; smart meters; and alternative energy. Among other things, Act 129 required utilities to complement those currently being offered was deniedfile with the PPUC an energy efficiency and peak load reduction plan, or EE&C Plan, by July 1, 2009, setting forth the utilities’ plans to reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of 4.5% by May 31, 2013. Act 129 also required utilities to file with the PPUC a Smart Meter Implementation Plan (SMIP).
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 with rates effective March 1, 2010.
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 November 2009, the Office of Consumer Advocate (OCA) filed an appeal with the Commonwealth Court of the PPUC’s October Order. The OCA contends that the PPUC’s Order failed to include WP’s costs for smart meter implementation in the EE&C Plan, and that inclusion of such costs would cause the EE&C Plan to exceed the statutory cap for EE&C expenditures. The OCA also contends that WP’s EE&C plan does not meet the Total Resource Cost Test. The appeal remains pending but has been stayed by the NJBPUCommonwealth Court pending possible settlement of WP’s SMIP. In September, 2010, WP filed an amended EE&C Plan that is less reliant on December 1,smart meter deployment, which the PPUC approved in January 2011.

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Met-Ed, Penelec and Penn jointly filed a SMIP with the PPUC in August 2009. On July 6,This plan proposed 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 of approximately $29.5 million, which the Pennsylvania Companies, in their plan, proposed to recover through an automatic adjustment clause. The ALJ’s Initial Decision approved the SMIP as modified by the ALJ, including: ensuring that the smart meters to be deployed include the capabilities listed in the PPUC’s Implementation Order; denying the recovery of interest through the automatic adjustment clause; providing for the recovery of reasonable and prudent costs net of resulting savings from installation and use of smart meters; and requiring that administrative start-up costs be expensed and the costs incurred for research and development in the assessment period be capitalized. In April 2010, the January 30, 2009 petition directed to infrastructure investment which had been pending beforePPUC adopted a Motion by Chairman Cawley that modified the NJBPU was withdrawn by JCP&L. ImplementationALJ’s initial decision, and decided various issues regarding the SMIP for Met-Ed, Penelec and Penn. The PPUC entered its Order in June 2010, consistent with the Chairman’s Motion. Met-Ed, Penelec and Penn filed a Petition for Reconsideration of a single portion of the remaining projects isPPUC’s Order regarding the future ability to include smart meter costs in base rates, which the PPUC granted in part by deleting language from its original order that would have precluded Met-Ed, Penelec and Penn from seeking to include smart meter costs in base rates at a later time. The costs to implement the SMIP could be material. However, assuming these costs satisfy a just and reasonable standard, they are expected to be recovered in a rider (Smart Meter Technologies Charge Rider) which was approved when the PPUC approved the SMIP.
In August 2009, WP filed its original SMIP, which provided for extensive deployment of smart meter infrastructure with replacement of all of WP’s approximately 725,000 meters by the end of 2014. 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 an Initial Decision dated April 29, 2010, an ALJ determined that WP’s alternative smart meter deployment plan, which contemplated deployment of 375,000 smart meters by May 2012, complied with the requirements of Act 129 and recommended approval of the alternative plan, including WP’s proposed cost recovery mechanism.
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 upon resolutionaspects of regulatory issues includingthe EE&C Plan. In October 2010, WP and Pennsylvania’s Office of Consumer Advocate 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 approximately 25,000 smart 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 the 30-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.
In December 2010, the PPUC directed that the SMIP proceeding be referred to the ALJ for further proceedings to ensure that the impact of the proposed merger with FirstEnergy is considered and that the Joint Petition for Settlement has adequate support in the record. 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. The proposed settlement also obligates OCA to withdraw its November 2009 appeal of the PPUC’s Order in WP’s EE&C plan proceeding. A Joint Stipulation with the OSBA was also filed on March 9, 2011. The proposed settlement remains subject to review by the ALJ, who will prepare an Initial Decision for consideration by the PPUC.
By Tentative Order entered in September 2009, the PPUC provided for an additional 30-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 above accounting method utilized by Met-Ed and Penelec. Met-Ed and Penelec are awaiting further action by the PPUC.
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. The PPUC has not yet initiated that investigation.

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Virginia
In September 2010, PATH-VA filed an application with the Virginia SCC for authorization to construct the Virginia portions of the PATH Project. On February 28, 2011, PATH-VA filed a motion to withdraw the application. See “Transmission Expansion” in the Federal Regulation and Rate Matters section for further discussion of this matter.
West Virginia
In August 2009, MP and PE filed with the WVPSC a request to increase retail rates by approximately $122.1 million annually, effective June 10, 2010. In January 2010, MP and PE filed supplemental testimony discussing a tax treatment change that would result in a revenue requirement approximately $7.7 million lower than the requirement included in the original filing. In addition, in December 2009, subsidiaries of MP and PE completed a securitization transaction to finance certain costs associated with the proposal.installation of scrubbers at the Fort Martin generating station, which costs would otherwise have been included in the request for rate recovery. Consequently, MP and PE ultimately requested an annual increase in retail rates of approximately $95 million, rather than $122.1 million. In April 2010, MP and PE filed with the WVPSC a Joint Stipulation and Agreement of Settlement reached with the other parties in the proceeding that provided for:
a $40 million annualized base rate increase effective June 29, 2010;
a deferral of February 2010 storm restoration expenses in West Virginia over a maximum five-year period;
an additional $20 million annualized base rate increase effective in January 2011;
a decrease of $20 million in ENEC rates effective January 2011, which amount is deferred for later recovery in 2012; and
a moratorium on filing for further increases in base rates before December 1, 2011, except under specified circumstances.
The WVPSC approved the Joint Petition and Agreement of Settlement in June 2010.
In 2009, the West Virginia Legislature enacted the Alternative and Renewable Energy Portfolio Act (Portfolio Act), 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, including ten percent by 2015, fifteen percent by 2020, and twenty-five percent by 2025. In November 2010, the WVPSC issued Rules Governing Alternative and Renewable Energy Portfolio Standard (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. Additionally, in January 2011, MP and PE filed an application with the WVPSC seeking to certify three facilities as Qualified Energy Resource Facilities. If the application is approved, the three facilities would then be capable of generating renewable credits which would assist the Companies in meeting their combined requirements under the Portfolio Act. Further, in February 2011, MP and PE filed a petition with the WVPSC seeking an Order declaring that MP is entitled to all alternative & 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 WV. The City of New Martinsville, the owner of one of the contracted resources, has filed an opposition to the Petition.
FERC Matters
Rates for Transmission Service Between MISO and PJM
In November 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 SECA) during a 16-month transition period. In 2005, the FERC set the SECA for hearing. The presiding ALJ issued an initial decision in August 2006, rejecting the compliance filings made by MISO, PJM and the transmission owners, and directing new compliance filings. This decision was subject to review and approval by the FERC. In May 2010, FERC issued an order denying pending rehearing requests and an Order on Initial Decision which reversed the presiding ALJ’s rulings in many respects. Most notably, these orders affirmed the right of transmission owners to collect SECA charges with adjustments that modestly reduce the level of such charges, and changes to the entities deemed responsible for payment of the SECA charges. The Ohio Companies were identified as load serving entities responsible for payment of additional SECA charges for a portion of the SECA period (Green Mountain/Quest issue). FirstEnergy executed settlements with AEP, Dayton and the Exelon parties to fix FirstEnergy’s liability for SECA charges originally billed to Green Mountain and Quest for load that returned to regulated service during the SECA period. The AEP, Dayton and Exelon, settlements were approved by the FERC in November 2010, and the relevant payments made. The Utilities have refund obligations that are under review by FERC as part of a compliance filing. Potential refund obligations of FirstEnergy are not expected to be material. Rehearings remain pending in this proceeding.

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PJM Transmission Rate
OnIn April 19, 2007, 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, 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 based on the amount of load served in a transmission zone. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a load flow methodology (DFAX), which is generally referred to as a “beneficiary pays” approach to allocating the cost of high voltage transmission facilities.
The FERC’s Opinion 494 order was appealed to the U.S. Court of Appeals for the Seventh Circuit, which issued a decision onin August 6, 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 new 500+ kV facilities on a load ratio share basis and, based on this finding, remanded the rate design issue back to FERC.
In an order dated January 21, 2010, FERC set the matter for “paper hearings”—meaning that FERC called for parties to submit comments or written testimony pursuant to the schedule described in the order. FERC identified nine separate issues for comments and directed PJM to file the first round of comments on February 22, 2010, with other parties submitting responsive comments and thethen reply comments.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 eastern utilities in PJM bearing the majority of theirthe costs. Numerous parties filed responsive comments or studies on May 28, 2010 and reply comments on June 28, 2010. FirstEnergy and a number of other utilities, industrial customers and state commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. Certain eastern utilities and their state commissions supported continued socialization of these costs on a load ratio share basis. FERCThis matter is expected to act beforeawaiting action by the end of the year.FERC.

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RTO ConsolidationRealignment
On December 17, 2009,February 1, 2011, ATSI in conjunction with PJM filed its proposal with FERC issued an order approving, subjectfor moving its transmission rate into PJM’s tariffs. FirstEnergy expects ATSI to certain future compliance filings, ATSI’s move to PJM. This move, which is expected to be effectiveenter PJM on June 1, 2011, allowsand that if legal proceedings regarding its rate are outstanding at that time, ATSI will be permitted to start charging its proposed rates, subject to refund. On April 1, 2011, the MISO Transmission Owners (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, to consolidate its transmission assets and operations into PJM. Currently, FirstEnergy’s transmission assets and operations are divided between PJM and MISO. The consolidation will make the transmission assets that are part of ATSI, whose footprint includes the Ohio Companies and Penn, part of PJM. In the order, FERC approved FirstEnergy’s proposal to use a Fixed Resource Requirement Plan (FRR Plan) to obtain capacity to satisfy the PJM capacity requirementsMISO submitted numerous filings for the 2011-12 and 2012-13 delivery years.
On December 17, 2009, ATSI executed the PJM Consolidated Transmission Owners Agreement and on December 18, 2009, the Ohio Companies and Penn executed the PJM Operating Agreement and the PJM Reliability Assurance Agreement. Executionpurpose of these agreements committed ATSI, the Ohio Companies and Penn to the move into PJM.
FirstEnergy successfully conducted the FRR auctions on March 19, 2010. Moreover, the ATSI-zone loads participated in the PJM base residual auction for the 2013 delivery year. Successful completioneffecting movement of these steps secured the capacity necessary for the ATSI footprintzone to meet PJM’s capacity requirements.
On September 4, 2009,PJM on June 1, 2011. These filings include clean-up of the PUCO opened a caseMISO’s tariffs (to remove the ATSI zone), submission of load and generation interconnection agreements to take comments from Ohio’s stakeholders regarding the RTO consolidation. On August 25, 2010, the PUCO issued an order that, among other things, committed the PUCO to close this case and also to withdraw its objections that were filed in the relevant FERC dockets conditioned upon the Ohio Companies not seeking recovery of MISO exit fees or PJM integration costs (estimated to be approximately $37 million as of September 30, 2010). Notwithstanding the PUCO’s actions, certain other parties protested aspects ofreflect the move into PJM, and certainsubmission of changes to PJM’s tariffs to support the move into PJM.
FERC proceedings are pending in which ATSI’s transmission rate, the exit fee payable to MISO, transmission cost allocations and costs associated with long term firm transmission rights payable by the ATSI zone upon its departure from the MISO are under review. The outcome of these matters remain outstanding and willproceedings cannot be resolved in future FERC proceedings. Under the terms of the ESP order issued August 25, 2010, the PUCO has agreed to close this docket.predicted.
MISO Multi-Value Project Rule Proposal
OnIn July 15, 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 Multi-Value Projects (MVPs)—MVPs—are a class of MTEP projects. The MISO proposesfiling 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. MISO expectsThe filing parties expect that itsthe 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. MISO hasThe filing parties requested that FERC rule on its MVP proposal by December, but has asked for an effective date for itsthe proposal of July 16, 2011. On August 19, 2010, MISO’s Board approved the first MVP project—project — the so-called “Michigan Thumb Project.” Under MISO’s proposal, the costs of MVP projects approved by MISO’s Board prior to the anticipated June 1, 2011 effective date of FirstEnergy’s integration into PJM would continue to be allocated to FirstEnergy. This approach is reflected in the MISO’sMISO estimated allocations of the costs for the Michigan Thumb Project, wherethat approximately $16$15 million in annual revenue requirements werewould be allocated to the ATSI zone.zone associated with the Michigan Thumb Project upon its completion.
OnIn September 10, 2010, FirstEnergy filed a protest to MISO’sthe MVP proposal. FirstEnergy believesproposal arguing that MISO’s proposal to allocate costs of MVP 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 to date in the ATSI move tointegration 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.

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In December 2010, FERC issued an order approving the MVP proposal without significant change. FERC’s order was not clear, however, as to 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 attach 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 filed for rehearing of FERC’s order. In its rehearing request, FirstEnergy argued that because the MVP rate is unableusage-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. FirstEnergy cannot predict the outcome of these proceedings at this time.
PJM Calculation Error
In March 2010, MISO filed two complaints at FERC against PJM relating to a previously-reported modeling error in PJM’s system that impacted the manner in which market-to-market power flow calculations were made between PJM and MISO since April 2005. MISO claimed that this error resulted in PJM underpaying MISO by approximately $130 million over the time period in question. Additionally, MISO alleged that PJM did not properly trigger market-to-market settlements between PJM and MISO during times when it was required to do so, which MISO claimed may have cost it $5 million or more. As PJM market participants, AE Supply and MP may be liable for a portion of any refunds ordered in this case. PJM, Allegheny and other PJM market participants filed responses to MISO complaints and PJM filed a related complaint at FERC against MISO claiming that MISO improperly called for market-to-market settlements several times during the same time period covered by the two MISO complaints filed against PJM, which PJM claimed may have cost PJM market participants $25 million or more. On January 4, 2011, an Offer of Settlement was filed at FERC that, if approved, would resolve all pending issues in the dispute. The Offer of Settlement calls for the withdrawal of all pending complaints with no payments being made by any parties. Initial comments on the Offer of Settlement were filed at FERC on January 24, 2011. FirstEnergy and Allegheny Energy filed comments supporting the proposed settlement. A report on the partially contested settlement was issued by the settlement judge to the FERC on March 9, 2011. On March 16, 2011, the settlement judge terminated the settlement proceedings and forwarded the partially contested settlement to the FERC for review. The case is awaiting a decision by the FERC.
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 California Department of Water Resources (CDWR) during 2001. The settlement proposal claims that CDWR is owed approximately $190 million for these alleged overcharges. This proposal was made in the context of mediation efforts by the 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 remanded one of those proceedings to the FERC, which arises out of claims previously filed with the 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 have 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. In April 2010, the California parties filed exceptions to the judge’s ruling with the FERC, and briefing is complete on those exceptions. The parties are awaiting a ruling from the FERC on the exceptions.
In June 2009, the California Attorney General, on behalf of certain California parties, filed a second lawsuit with the 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 the joining of AE Supply in this new lawsuit. AE Supply has filed a motion to dismiss the Brown case that is pending before the FERC. No scheduling order has been entered in the Brown case. Allegheny intends to vigorously defend against these claims but cannot predict their outcome.
Transmission Expansion
TrAIL Project.TrAIL is a 500 kV transmission line currently under construction that will extend from southwest Pennsylvania through West Virginia and into northern Virginia. On April 15, 2011, the TrAIL 500 kV line segment from Meadowbrook substation to Loudoun substation in Virginia was successfully energized and is carrying load. The other segments are planned to be energized in May. The entire TrAIL line is scheduled to be completed and placed in service no later than June 2011.
PATH Project.The PATH Project is comprised of a 765 kV transmission line that is 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.

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PJM initially authorized construction of the PATH Project in June 2007 and, on June 17, 2010, requested that PATH, LLC proceed with all efforts related to the PATH Project, including state regulatory proceedings, assuming a required in-service date of June 1, 2015. 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 potential 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 and the WVPSC has granted the motion to withdraw. The VSCC has not ruled on the motion to withdraw.
PATH, LLC 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 return on equity 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 a 1.5% return on equity incentive adder and a 0.50% return on equity adder for RTO participation. These adders will be applied to the base return on equity determined as a result of the hearing. PATH, LLC is currently engaged in settlement discussions with the staff of FERC and intervenors regarding resolution of the base return on equity. FirstEnergy cannot predict the outcome of this matter.proceeding or whether it will have a material impact on its operating results.
Sales to Affiliates
FES has received authorization from the FERC to make wholesale power sales to affiliated regulated utilities in New Jersey, Ohio, and Pennsylvania. FES actively participates in auctions conducted by or on behalf the regulated affiliates to obtain power necessary to meet the utilities’ POLR obligations. AE Supply, a merchant affiliate acquired in the FirstEnergy-Allegheny merger, also participates in these auctions, and obtains prior FERC authorization when necessary to make sales to FE affiliates.
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 SO2SO2 and NOXNOx emissions regulations under the CAA. FirstEnergy complies with SO2 and NOx reduction requirements under the CAA and SIP(s) under the CAA by burning lower-sulfur fuel, combustion controls and post-combustion controls, generating more electricity from lower-emitting plants and/or using emission allowances. Violations can result in the shutdown of the generating unit involved and/or civil or criminal penalties.

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The Sammis, Burger, Eastlake and Mansfield coal-fired plants are operated under a consent decree with the EPA and DOJ that requires reductions of NOXNOx and SO2 emissions through the installation of pollution control devices or repowering. OE and Penn are subject to stipulated penalties for failure to install and operate such pollution controls or complete repowering in accordance with that agreement. Capital expenditures necessary to complete requirements of the consent decree, including repowering Burger Units 4 and 5 for biomass fuel combustion, are currently estimated to be approximately $399 million for 2010-2012.
In 2007, PennFutureJuly 2008, three complaints were filed a citizen suit under the CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations,against FGCO in the U.S. District Court for the Western District of Pennsylvania. In July 2008, three additional complaints were filed against FGCOPennsylvania seeking damages based on Bruce Mansfield Plant air emissions. Two of 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 of twenty-one individuals and the other being a class action complaint seeking certification as a class action with the eight named plaintiffs as the class representatives. A settlement was reached with PennFuture. FGCO believes the claims of the remaining plaintiffs are without merit and intends to defend itself against the allegations made in thosethese three complaints.

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The states of New Jersey and Connecticut filed CAA citizen suits in 2007 alleging NSR violations at the Portland Generation Station against GenOn Energy, Inc. (formerly RRI Energy, Inc. (theand 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.Energy, and Met-Ed is unable to predict the outcome of this matter.
In January 2009, the EPA issued a NOV to ReliantGenOn Energy, Inc. alleging NSR violations at the Portland Generation Station based on “modifications” dating back to 1986 and also alleged NSR violations at the Keystone and Shawville Stations based on “modifications” dating back to 1984. Met-Ed, JCP&L, as the former owner of 16.67% of the Keystone Station, and Penelec, as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter.
In June 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. (Mission) alleging that “modifications” at the Homer City Power Station occurred sincefrom 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, Energy Westside, Inc., Penelec, New York State Electric & Gas Corporation and others that have had an ownership interest in the Homer City Power Station containing in all material respects allegations identical allegations asto those included in the June 2008 NOV. On July 20, 2010, the states of New York and Pennsylvania provided Mission, Energy Westside, Inc., Penelec, NYSEG and others that have had an ownership interest in the Homer City Power Station a notification that was required 60 days prior to filing a citizen suit under the CAA. 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 the Homer City Power Station 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, New York State Electric and Gas Corporation, and various current owners of the Homer City Station, including EME Homer City Generation L.P. and affiliated companies, including Edison International. 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 the Homer City Station’s air emissions as well as certification as a class action and to enjoin the Homer City Station from operating except in a “safe, responsible, prudent and proper manner.” Penelec believes the claims are without merit and intends to defend itself against the allegations made in the complaint, but, at this time, is unable to predict the outcome of this matter. In addition, the Commonwealth of Pennsylvania and the States of New Jersey and New York intervened and have filed separate complaints regarding the Homer City Station seeking injunctive relief and civil penalties. Mission Energy Westside, Inc. is seeking indemnification from Penelec, the co-owner and operator of the Homer City Power Station prior to its sale in 1999. The scope of Penelec’s indemnity obligation to and from Mission Energy Westside, Inc. is under dispute and Penelec is unable to predict the outcome of this matter.
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 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. FGCO 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 generating plant may constitute a major modification under the NSR provision of the CAA. Later in 2009, FGCO also received another information request regarding emission projections for the Eastlake generating plant. FGCO intends to comply with the CAA, including the EPA’s information requests but, at this time, is unable to predict the outcome of this matter.
In August 2000, AE received a letter from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the following ten electric generation facilities, which collectively include 22 generation units: Albright, Armstrong, Fort Martin, Harrison, Hatfield’s Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island. The letter requested information under Section 114 of the CAA to determine compliance with the CAA and related requirements, including potential application of the NSR standards under the CAA, which can require the installation of additional air emission control equipment when the 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.
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 facilities: 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 generation facilities 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.

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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 Hatfield’s Ferry, Armstrong and Mitchell facilities in Pennsylvania. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. In May 2006, the District Court denied Allegheny’s motion to dismiss the amended complaint. In July 2006, the Court determined that discovery would proceed regarding liability issues, but not remedies. Discovery on the liability phase closed on December 31, 2007, and summary judgment briefing was completed during the first quarter of 2008. In November 2008, the District Court issued a Memorandum Order denying all motions for summary judgment and establishing certain legal standards to govern at trial. In December 2009, a new trial judge was assigned to the case, who then entered an order granting a motion to reconsider the rulings in the November 2008 Memorandum Order. In April 2010, the new judge issued an opinion, again denying all motions for summary judgment and establishing certain legal standards to govern at trial. The 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.
In September 2007, Allegheny also 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 Hatfield’s Ferry and Armstrong generation facilities in Pennsylvania and the Fort Martin and Willow Island generation facilities in West Virginia.
FirstEnergy intends to vigorously defend against the CAA matters described above but cannot predict their outcomes.
State Air Quality Compliance
In early 2006, Maryland passed the Healthy Air Act, which imposes state-wide emission caps on SO2 and NOX, requires mercury emission reductions and mandates that Maryland join the RGGI and participate in that coalition’s regional efforts to reduce CO2 emissions. On April 20, 2007, Maryland became the 10th state to join the RGGI. The Healthy Air Act provides a conditional exemption for the R. Paul Smith power station for NOX, SO2 and mercury, based on a PJM declaration that the station is vital to reliability in the Baltimore/Washington DC metropolitan area, which PJM determined in 2006. Pursuant to the legislation, the Maryland Department of the Environment (MDE) passed alternate NOX and SO2 limits 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 of 80% beginning in 2010. The statutory exemption does not extend to R. Paul Smith’s CO2 emissions. Maryland issued final regulations to implement RGGI requirements in February 2008. Ten RGGI auctions have been held through the end of calendar year 2010. 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. FirstEnergy is unable to predict the outcome of this matter.
In January 2010, the WVDEP issued a NOV for opacity emissions at Allegheny’s Pleasants generating facility. FirstEnergy is discussing with WVDEP steps to resolve the NOV including installing a reagent injection system to reduce opacity.
National Ambient Air Quality Standards
The EPA’s CAIR requires reductions of NOXNOx and SO2 emissions in two phases (2009/2010 and 2015), ultimately capping SO2 emissions in affected states to 2.5 million tons annually and NOXNOx emissions to 1.3 million tons annually. In 2008, the U.S. Court of Appeals for the District of Columbia Circuit 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“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 2010, the EPA proposed the Clean Air Transport Rule (CATR) to replace CAIR, which remains in effect until the EPA finalizes CATR. CATR requires reductions of NOXNOx and SO2 emissions in two phases (2012 and 2014), ultimately capping SO2 emissions in affected states to 2.6 million tons annually and NOXNOx emissions to 1.3 million tons annually. The EPA proposed a preferred regulatory approach that allows trading of NOXNOx and SO2 emission allowances between power plants located in the same state and severely limits interstate trading of NOx and SO2 emission allowances. The EPA also requested comment on two alternative approaches—the first eliminates interstate trading of NOXNOx and SO2 emission allowances and the second eliminates trading of NOXNOx and SO2 emission allowances in its entirety. Depending on the actions taken by the EPA with respect to CATR, the proposed MACT regulations discussed below and any future regulations that are ultimately implemented, FGCO’s future cost of compliance may be substantial. Management is currently assessing the impact of these environmental proposals and other factors on FGCO’s facilities, particularly on the operation of its smaller, non-supercritical units. For example, as disclosed herein, management decided to idle certain units or operate them on a seasonal basis until developments clarify.

 

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Hazardous Air Pollutant Emissions
The EPA’s CAMR provides for a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping nationwide emissions of mercury at 38 tons by 2010 (as a “co-benefit” from implementation of SO2 and NOX emission caps under the EPA’s CAIR program) and 15 tons per year by 2018. The U.S. Court of Appeals for the District of Columbia, at the urging of several states and environmental groups, vacated the CAMR, ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. On April 29, 2010, the EPA issued proposed maximum achievable control technology (MACT) regulations requiring emissions reductions of mercury and other hazardous air pollutants from non-electric generating unit boilers, including boilers which do not use fossil fuels such as the proposed Burger biomass repowering project. On September 1, 2010, the EPA classified Burger as an existing source for purposes of the industrial Boiler MACT. If finalized, the non-electric generating unit MACT regulations could also provide precedent for MACT standards applicable to electric generating units. The EPA entered into a consent decree requiring it to propose MACT regulations for mercury and other hazardous air pollutants from electric generating units by March 16, 2011, the EPA released its MACT proposal to establish emission standards for mercury, hydrochloric acid and to finalize the regulations by November 16, 2011.various metals for electric generating units. Depending on the action taken by the EPA and on how any future regulations are ultimately implemented, FGCO’sFirstEnergy’s future cost of compliance with MACT regulations may be substantial and changes to FGCO’sFirstEnergy’s operations may result.
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, onin June 26, 2009. The Senate continues to consider a number of measures to regulate GHG emissions. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuringproposals to ensure that 10% of electricity used in the United States comes from renewable sources by 2012, increasingto increase to 25% by 2025, and implementingto implement an economy-wide cap-and-trade program to reduce GHG emissions by 80% by 2050. State activities,Certain states, primarily the northeastern states participating in the Regional Greenhouse Gas InitiativeRGGI 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 will requirerequired FirstEnergy to measure GHG emissions commencing in 2010 and will require it to submit reports commencing in 2011. 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 of 75,000 tons per year (tpy) of carbon dioxide equivalents (CO2e) effective January 2, 2011 for existing facilities under the CAA’s PSD program, but untilprogram. Until July 1, 2011, thatthis emissions applicability threshold will only apply if PSD is triggered by non-carbon dioxidenon-CO2 pollutants.
At the international level, the Kyoto Protocol, signed by the U.S. in 1998 but never submitted for ratification by the U.S. Senate, was intended to address global warming by reducing the amount of 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 below two degrees Celsius; includeincludes a commitment by developed countries to provide funds, approaching $30 billion over the next three years with a goal of increasing to $100 billion by 2020; and establishestablishes the “Copenhagen 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.

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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. The U.S. Supreme Court granted a writ of certiorari to review the decision of the Second Circuit. Oral argument was held on April 19, 2011, and a decision is expected by July 2011. While FirstEnergy is not a party to this litigation, FirstEnergy and/or one or more of its subsidiaries could be named in actions making similar allegations.
FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO2 emissions per KWH of electricity generated by FirstEnergy is lower than many 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 Act 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.
The EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing 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). 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. OnIn April 1, 2009, the U.S. Supreme Court reversed one significant aspect of the Second Circuit’s opinion and decided that Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. TheOn March 28, 2011, the EPA is developingreleased a new proposed regulation under Section 316(b) of the Clean Water Act consistent withgenerally requiring fish impingement to be reduced to a 12% annual average and studies to be conducted at the opinionsmajority of the Supreme Courtour existing generating facilities to assist permitting authorities to determine whether and the Courtwhat site-specific controls, if any, would be required to reduce entrainment of Appeals which have created significant uncertainty about the specific nature, scope and timing of the final performance standard.aquatic life. 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. On March 15,In November 2010, the Ohio EPA issued a draft permit for the Bay Shore power plant requiring installation of reverse louvers in its entire water intake channel by December 31, 2014. Depending on the results of such studies and the EPA’s further rulemaking and any final action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.
In June 2008,April 2011, the U.S. Attorney’s Office in Cleveland, Ohio advised FGCO that it is no longer considering prosecution under the Clean Water Act and the Migratory Bird Treaty Act for three petroleum spills at the Edgewater, Lakeshore and Bay Shore plants which occurred on November 1, 2005, January 26, 2007 and February 27, 2007. This matter has been referred back to EPA for civil enforcement and FGCO is unable to predict the outcome of this matter.
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 Hatfield’s Ferry generation facility. 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 significant costs or negatively affect its ability to operate the scrubbers as designed. Preliminary studies indicate an initial capital investment in excess of $150 million in order to install technology to meet the TDS and sulfate limits in the permit. 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. The hearing is scheduled to begin on September 13, 2011. AE Supply intends to vigorously pursue these issues, but cannot predict the outcome of these appeals.
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 Clean Water Act 303(d) list to the EPA with a recommended sulfate impairment designation for an approximately 68 mile stretch of the Monongahela River north of the West Virginia border. EPA has not acted on PA DEP’s recommendation. If the designation is approved, Pennsylvania will then need to develop a TMDL limit for the river, a process that will take about five years. Based on the stringency of the TMDL, FirstEnergy may incur significant costs to reduce sulfate discharges into the Monongahela River from its Hatfield’s Ferry and Mitchell facilities in Pennsylvania and its Fort Martin facility in West Virginia.

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In October 2009, the WVDEP issued the water discharge permit for the Fort Martin generation facility. Similar to the Hatfield’s Ferry water discharge permit issued for the scrubber project, 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 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.
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.
OnIn December 30, 2009, in an advanced 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. OnIn May 4, 2010, the EPA 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. FGCO’sFirstEnergy��s future cost of compliance with any coal combustion residuals 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.

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The UtilitiesUtility Registrants have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the consolidated balance sheet as of September 30, 2010,March 31, 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 $105$104 million (JCP&L — $76$69 million, TE — $1 million, CEI — $1 million, FGCO — $1 million and FirstEnergy — $26$32 million) have been accrued through September 30, 2010.March 31, 2011. Included in the total are accrued liabilities of approximately $67$64 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.
Other Legal Proceedings
Power Outages and Related Litigation
In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L’s territory.&L. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages due to the outages. After various motions, rulings and appeals, the Plaintiffs’ claims for consumer fraud, common law fraud, negligent misrepresentation, strict product liability and punitive damages were dismissed, leaving only the negligence and breach of contract causes of actions. On July 29, 2010, the Appellate Division upheld the trial court’s decision decertifying the class. Plaintiffs have filed, and JCP&L has opposed, a motion for leave to appeal to the New Jersey Supreme Court. JCP&L is waiting forIn November 2010, the Supreme Court issued an order denying Plaintiffs’ motion. The Court’s decision.
Litigation Relating toorder effectively ends the Proposed Allegheny Energy Merger
In connection with the proposed merger (Note 16), purported shareholders of Allegheny Energy have filed putative shareholder class action and/or derivative lawsuits against Allegheny Energyattempt, and its directors and certain officers, referredleaves only nine (9) plaintiffs to as the Allegheny Energy defendants, FirstEnergy and Merger Sub. Four putative class action and derivative lawsuits were filed in the Circuit Court for Baltimore City, Maryland (Maryland Court). One was withdrawn.pursue their respective individual claims. The Maryland Court has consolidated the remaining three cases under the caption: In re Allegheny Energy Shareholder and Derivative Litigation, C.A. No. 24-C-10-1301. Three shareholder lawsuits were filed in the Court of Common Pleas of Westmoreland County, Pennsylvania and the court has consolidated these actions under the caption: In re Allegheny Energy, Inc. Shareholder Class and Derivative, Litigation, Lead Case No. 1101 of 2010. One putative shareholder class action was filed in the U.S. District Court for the Western District of Pennsylvania and is captioned Louisiana Municipal Police Employees’ Retirement System v. Evanson, et al., C.A. No. 10-319 NBF. In summary, the lawsuits allege, among other things, that the Allegheny Energy directors breachedindividual plaintiffs have not taken any affirmative steps to pursue their fiduciary duties by approving the merger agreement, and that Allegheny Energy, FirstEnergy and Merger Sub aided and abetted in these alleged breaches of fiduciary duty. The complaints seek, among other things, jury trials, money damages and injunctive relief. While FirstEnergy believes the lawsuits are without merit and has defended vigorously against the claims, in order to avoid the costs associated with the litigation, the defendants have agreed to the terms of a disclosure-based settlement of all these shareholder lawsuits and have reached agreement with counsel for all of the plaintiffs concerning fee applications. Under the terms of the settlement, no payments are being made by FirstEnergy or Merger Sub. A formal stipulation of settlement was filed with the Maryland Court on October 18, 2010 and agreements have been signed with plaintiffs in the Pennsylvania proceedings to dismiss those actions once the settlement is approved by the Maryland Court. The Maryland judge has preliminarily approved the stipulation of settlement and set the final approval hearing date for December 13, 2010. If the parties are unable to obtain final approval of the settlement, then litigation will proceed, and the outcome of any such litigation is inherently uncertain. If a dismissal is not granted or a settlement is not reached, these lawsuits could prevent or delay the completion of the merger and result in substantial costs to FirstEnergy. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger closes may adversely affect FirstEnergy’s business, financial condition or results of operations.
Nuclear Plant Matters
During a planned refueling outage that began on February 28, 2010, FENOC conducted a non destructive examination and testing of the Control Rod Drive Mechanism (CRDM) nozzles of the Davis-Besse reactor pressure vessel head. FENOC identified flaws in CRDM nozzles that required modification. The NRC was notified of these findings, along with federal, state and local officials. On March 17, 2010, the NRC sent a special inspection team to Davis-Besse to assess the adequacy of FENOC’s identification, analyses and resolution of the CRDM nozzle flaws and to ensure acceptable modifications were made prior to placing the RPV head back in service. After successfully completing the modifications, FENOC committed to take a number of corrective actions including strengthening leakage monitoring procedures and shutting Davis-Besse down no later than October 1, 2011, to replace the reactor pressure vessel head with nozzles made of material less susceptible to primary water stress corrosion cracking, further enhancing the safe and reliable operations of the plant. On June 29, 2010, FENOC returned Davis-Besse to service. On September 9, 2010, the NRC held a public exit meeting describing the results of the NRC special inspection team inspection of FENOC’s identification of the CRDM nozzles with flaws and the modifications to those nozzles. On October 22, 2010, the NRC issued its final report of the special inspection. The report contained three findings characterized as very low safety significance that were promptly corrected prior to plant operation.individual claims.

 

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On April 5, 2010, the Union of Concerned Scientists (UCS) requested that the NRC issue a Show Cause Order, or otherwise delay the restart of the Davis-Besse Nuclear Power Station until the NRC determines that adequate protection standards have been met and reasonable assurance exists that these standards will continue to be met after the plant’s operation is resumed. By a letter dated July 13, 2010, the NRC denied UCS’s request for immediate action because “the NRC has conducted rigorous and independent assessments of returning the Davis-Besse reactor vessel head to service and its continued operation, and determined that it was safe for the plant to restart.” The UCS petition was referred to a petition manager for further review. What additional actions, if any, that the NRC takes in response to the UCS request have not been determined.Plant Matters
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of obligations. As of September 30, 2010,March 31, 2011, FirstEnergy had approximately $2.0$2 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. FirstEnergy provides an additional $15 million parental guarantee associated with the funding of decommissioning costs for these units. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy’s nuclear decommissioning trusts fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy’s 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 nuclear decommissioning trusts. The NRC issued guidance anticipating an increase in low-level radioactive waste disposal costs associated with the decommissioning of FirstEnergy’s nuclear facilities. 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. This estimate encompasses the shortfall covered by the existing $15 million parental guarantee. FENOC agreed to increase the parental guarantee to $95 million within 90 days of the submittal.
In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse Nuclear Power Station operating license for an additional twenty years, until 2037. By an order dated April 26, 2011, the NRC Atomic Safety and Licensing Board (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 regarding (1) a combination of renewable alternatives to the renewal of Davis-Besse’s operating license, and (2) the cost of mitigating a severe accident at Davis-Besse. FENOC is currently evaluating these developments and considering an appropriate response. On April 14, 2011, a group of environmental organizations petitioned the NRC Commissioners to suspend all pending nuclear license renewal proceedings, including the Davis-Besse proceeding, to ensure that any safety and environmental implications of the Fukushima Daiichi Nuclear Power Station event in Japan are considered.
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 failure to begin accepting spent nuclear fuel on January 31, 1998. DOE was required to so commence 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. On January 18, 2011, the parties, FirstEnergy and DOJ, filed a joint status report that established a schedule for the litigation of these claims. FirstEnergy filed damages schedules and disclosures with the DOJ on February 11, 2011, seeking approximately $57 million in damages for delay costs incurred through September 30, 2010. The damage claim is subject to review and audit by DOE.
Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.
OnIn 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. OnIn March 18, 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, which has not yet rendered an opinion.
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.
FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy’s or its subsidiaries’ financial condition, results of operations and cash flows.
NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
See Note 1112 of the Combined Notes to the Consolidated Financial Statements (Unaudited) for discussion of new accounting pronouncements.

 

98116

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 (excluding the Allegheny facilities), and owns FirstEnergy’s nuclear generation facilities, respectively. FENOC, a wholly owned subsidiary of FirstEnergy, operates and maintains the nuclear generating facilities.
FES’ revenues are derived from sales to individual retail customers, sales to communities in the form of government aggregation programs, the sale of electricity to Met-Ed and Penelec to meet all of their POLR and default service requirements, and its participation in affiliated and non-affiliated POLR auctions. FES sales are primarily concentrated in Ohio, Pennsylvania, Illinois, Maryland, Michigan and New Jersey. 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 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 above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Net incomeEarnings available to parent decreased by $491$44 million in the first ninethree months of 2010,2011 compared to the same period of 2009.2010. The decrease was primarily due to a $292 million impairment charge ($181 million net of tax) related to operational changes at certain smaller coal-fired units in response to the continued slow economy, lower demand for electricityincreased transmission expenses, an inventory valuation adjustment, non-core asset impairments and uncertainty related to proposed new federal environmental regulations. In addition, the absence of a $252 million ($158 million after tax) gain in 2009 from the sale of a 9% participation interest in OVEC, lower investment income from the nuclear decommissioning trusts and a decrease in sales margins also contributed to the decline in net income.mark-to-market accounting.
Revenues
Excluding the impact of the 2009 gain on the OVEC sale, totalTotal revenues increased $836$3 million in the first ninethree months of 2010,2011, compared to the same period of 2009,2010, primarily due to an increasegrowth in direct and government aggregation sales, volumes and sales of RECs, partially offset by decreases in POLR sales to the Ohio Companies and wholesale sales.
The increase in revenues resulted from the following sources:
                        
 Nine Months    Three Months   
 Ended September 30 Increase  Ended March 31 Increase 
Revenues by Type of Service 2010 2009 (Decrease)  2011 2010 (Decrease) 
 (In millions)  (In millions) 
Direct and Government Aggregation $1,814 $406 $1,408  $840 $512 $328 
POLR 1,911 2,369  (458) 369 673  (304)
Other Wholesale 322 503  (181) 96 91 5 
Transmission 58 57 1  26 17 9 
RECs 67 — 67  32 67  (35)
Sale of OVEC participation interest — 252  (252)
Other 84 85  (1) 28 28 — 
              
Total Revenues
 $4,256 $3,672 $584  $1,391 $1,388 $3 
              
             
  Three Months    
  Ended March 31  Increase 
MWH Sales by Type of Service 2011  2010  (Decrease) 
  (In thousands)     
Direct  9,671   5,854   65.2%
Government Aggregation  4,310   2,732   57.8%
POLR  5,714   13,276   (57.0)%
Wholesale  1,113   898   23.9%
          
Total Sales
  20,808   22,760   (8.6)%
          

117

The increase in direct and government aggregation revenues of $1,408$328 million resulted from increased revenue from the acquisition of new commercial and industrial customers as well asand new government aggregation contracts with communities in Ohio, that provided generation to 1.2 million residential and small commercial customers at the end of September 2010 compared to 500,000 such customers at the end of September 2009, partially offset by lower unit prices. Inin addition, sales to residential and small commercial customers were bolstered by weather in the delivery area that was 69% warmer5.2% colder than in 2009.2010.

99

The decrease in POLR revenues of $458$304 million was due to lower sales volumes to the Pennsylvania and Ohio Companies, and lower unit prices, partially offset by increased sales volumesto non-associated companies and higher unit prices to the Pennsylvania Companies. The lowerParticipation in POLR auctions and RFPs are expected to continue, but the concentration of these sales volumeswill primarily be dependent on our success in our direct retail and unit prices to the Ohio Companies in 2010 reflected the results of the May 2009 power procurement process. Theaggregation sales channels.
Wholesale revenues increased revenues from the Pennsylvania Companies resulted from FES supplying Met-Ed and Penelec with volumes previously supplied through a third-party contract and at prices that were slightly higher than in 2009.
Other wholesale revenues decreased $181$5 million due to reducedincreased volumes andpartially offset by lower wholesale prices. The lowerhigher sales volumes were the result of increased short term (net hourly position) transactions in MISO. $22 million of wholesale revenue resulted from long positions in MISO that were unable to be netted with short positions in PJM, due to available capacity serving increased retail sales in Ohio. In July 2010, FES entered into financial transactions that offset the mark-to-market impact of legacy purchased power contracts totaling 500 MW entered into in 2008 for delivery in 2010 and 2011 and which have been marked to market since December 2009. These financial transactions mitigate the volatility of these contracts through the end of 2011 and resulted in revenues of $13 million in 2010.separate settlement requirements within each RTO.
The following tables summarize the price and volume factors contributing to changes in revenues from generation sales:
     
  Increase 
Source of Change in Direct and Government Aggregation (Decrease) 
  (In millions) 
Direct Sales:    
Effect of increase in sales volumes $909 
Change in prices  (73)
    
   836 
    
Government Aggregation    
Effect of increase in sales volumes  570 
Change in prices  2 
    
   572 
    
Net Increase in Direct and Gov’t Aggregation Revenues
 $1,408 
    
     
  Increase 
Source of Change in Wholesale Revenues (Decrease) 
  (In millions) 
POLR:    
Effect of decrease in sales volumes $(200)
Change in prices  (258)
    
   (458)
    
Other Wholesale:    
Effect of decrease in sales volumes  (147)
Change in prices  (34)
    
   (181)
    
Net Decrease in Wholesale Revenues
 $(639)
    
The sale of RECs resulted in gains of $67 million in the nine months ended September 2010.
     
  Increase 
Source of Change in Direct and Government Aggregation (Decrease) 
  (In millions) 
Direct Sales:    
Effect of increase in sales volumes $223 
Change in prices  (4)
    
   219 
    
Government Aggregation:    
Effect of increase in sales volumes  100 
Change in prices  9 
    
   109 
    
Net Increase in Direct and Government Aggregation Revenues
 $328 
    
     
  Increase 
Source of Change in POLR Revenues (Decrease) 
  (In millions) 
POLR:    
Effect of decrease in sales volumes $(384)
Change in prices  80 
    
   (304)
    
     
  Increase 
Source of Change in Wholesale Revenues (Decrease) 
  (In millions) 
Wholesale:    
Effect of increase in sales volumes  12 
Change in prices  (7)
    
   5 
    
Transmission revenues increased $1$9 million due primarily to higher MISO congestion revenue, offset by lower PJM congestion revenue.revenues. The revenues derived from the sale of RECs declined $35 million in the first quarter of 2011.
Expenses
Total operating expenses increased $1.2 billion$81 million in the first ninethree months of 2010,2011, compared with the same period of 2009.2010.

 

100118

The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first ninethree months of 2010, from2011, compared with the same period last year:
        
 Increase  Increase 
Source of Change in Fuel and Purchased Power (Decrease)  (Decrease) 
 (In millions)  (In millions) 
Fossil Fuel:  
Change due to increased unit costs $30 
Change due to decreased unit costs $(22)
Change due to volume consumed 135  31 
      
 165  9 
      
Nuclear Fuel:  
Change due to increased unit costs 23  6 
Change due to volume consumed 3  — 
      
 26  6 
      
Non-affiliated Purchased Power:  
Power contract mark-to-market adjustment 43 
Change due to decreased unit costs  (84)
Change due to increased unit costs 32 
Change due to volume purchased 650   (185)
      
 609   (153)
      
Affiliated Purchased Power:  
Change due to increased unit costs 81  20 
Change due to volume purchased 15   (12)
      
 96  8 
      
Net Increase in Fuel and Purchased Power Costs
 $896 
Net Decrease in Fuel and Purchased Power Costs
 $(130)
      
Fossil fuel costs increased $165$9 million in the first ninethree months of 2010,2011, compared to the same period of 2009,2010, as a result of higher generation volumes consumed combined with increasedat the fossil units, partially offset by decreased fossil unit prices. Increased volume reflects higher generation in the first nine months of 2010, compared to the same period last year due to improving economic conditions. The increased costs reflect higher coal and transportation charges in the first nine months of 2010, compared to the same period last year. Nuclear fuel costs increased $26 millioncosts. Fossil unit prices declined primarily due to the replacement of nuclearimproved generating unit availability at more efficient units, partially offset by increased coal transportation costs. Nuclear fuel atexpenses increased primarily due to higher unit costsprices following the refueling outages that occurred in 2009.2010.
Non-affiliated purchased power costs increased $609decreased $153 million due primarily to higherlower volumes purchased, and a power contract mark-to-market adjustment, partially offset by lowerhigher unit costs. The increasedecrease in volume primarily relates to the assumptionabsence in 2011 of a 1,300 MW third party contract fromassociated with serving Met-Ed and Penelec. Affiliated$35 million of purchased power increased $96 million primarilyexpense resulted from long positions in MISO that were unable to be netted with short positions in PJM, due to higher unit costs combined with higher volumes purchased from affiliated companies.separate settlement requirements within each RTO.
Other operating expenses increased $25$191 million in the first ninethree months of 2010,2011, compared to the same period of 2009, primarily due to2010, as a result of increased RTO transmission expensescosts ($36111 million), from $111 million in the first nine months of 2009 to $147 million in the same time period of 2010, primarily due to increased sales volumesan inventory valuation adjustment ($54 million) and increased uncollectible customer accountsnuclear operating costs ($15 million) related to higher labor and agent fees ($22 million) associated with the growth in direct and government aggregation sales,related benefits, partially offset by lower nuclear ($39 million)professional and fossil ($18 million) operating costs. Nuclear operating costs decreased primarily due to lower labor, consulting and contractor costs. The first nine months of 2010 had one less refueling outage and fewer extended outages than the same period of 2009. Fossil operating costs decreased primarily due to lower labor costs.
In the first ninethree month of 20102011, impairment charges of long-lived assets increased expenses by $294 million primarily due to a $292 million impairment charge ($181 million net of tax) related to operational changes at certain smaller coal-fired units in response to the continued slow economy, lower demand for electricity, as well as uncertainty related to proposed new federal environmental regulations. As a result of this impairment depreciation expense decreased in the first nine month of 2010 compared to the same time period of 2009.$14 million.
General taxes increased $5$2 million due to sales taxes associated with increased revenues.an increase in revenue-related taxes.
Other Expense
Total other expense increased $128decreased $9 million in the first ninethree months of 2010,2011, compared to the same period of 2009,2010, primarily due to a decreasean increase in nuclear decommissioning trustmiscellaneous income ($16 million) and increased investment income ($945 million) combined with, partially offset by an increase in interest expense (net of capitalized interest)interest — $12 million). InterestIncreased miscellaneous income was the result of mark-to-market adjustments on power related derivatives. Increased investment income was the result of higher nuclear decommissioning trust investment income. The increase in interest expense was the result of reduced capitalized interest associated with the completion of the Sammis AQC project in 2010 combined with increased primarily due to new long-term debt issued combinedinterest expense associated with the restructuring of existing PCRBs.certain variable rate PCRBs into fixed rate modes.

 

101119

OHIO EDISON COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
OE is a wholly owned electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. They procure generation services for those franchise customers electing to retain OE and Penn as their power supplier.
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 above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Earnings available to parent increaseddecreased by $40$6 million in the first ninethree months of 2010,2011, compared to the same period of 2009.2010. The increasedecrease primarily resulted from lower purchased power costsrevenues and higher other operating costs, partially offset by lower revenuespurchased power costs and investment income.amortization of regulatory assets.
Revenues
Revenues decreased $589$116 million, or 29%23%, in the first ninethree months of 2010,2011, compared with the same period in 2009,2010, due primarily to a decrease in generation revenues, partially offset by higher distribution revenues.
Distribution revenues increased $10 million in the first three months of 2011, compared to the same period in 2010, primarily due to an increase in KWH deliveries and higher average prices in all customer classes. The higher KWH deliveries in the residential class were influenced by increased weather-related usage in the first three months of 2011, reflecting a 5% increase in heating degree days in OE’s service territory.
Changes in distribution KWH deliveries and revenues in the first three months of 2011, compared to the same period in 2010, are summarized in the following tables:
Distribution KWH DeliveriesIncrease
Residential1.4%
Commercial1.2%
Industrial9.3%
Increase in Distribution Deliveries
3.7%
     
Distribution Revenues Increase 
  (In millions) 
Residential $7 
Commercial  1 
Industrial  2 
    
Increase in Distribution Revenues
 $10 
    
Retail generation revenues decreased $584$127 million primarily due to a decrease in KWH sales and lower average prices in all customer classes. Retail generation obligations are attributable to non-shopping customers and are procured through full-requirements auctions. OE defers the difference between retail generation revenues and costs, resulting in no material effect to current period earnings. Lower KWH sales were primarily the result of a 42% increase inincreased customer shopping, in the first nine months of 2010. That condition is expected to continue to impact the comparative sales levels for the remainder of 2010. Lower KWH sales to residential customers were partially offset by increased weather-related usage in the first ninethree months of 2010, reflecting an 87% increase in cooling degree days in OE’s service territory. Decreased volumes were partially offset by higher average prices in the commercial and industrial classes. Higher average prices in the commercial and industrial classes resulted from the CBP auction for the service period beginning June 1, 2009.2011, as described above.

120

Changes in retail generation KWH sales and revenues in the first ninethree months of 2010,2011, compared to the same period in 2009,2010, are summarized in the following tables:
     
Retail Generation KWH Sales Decrease 
     
Residential  (26.033.0)%
Commercial  (60.043.2)%
Industrial  (62.716.3)%
    
Decrease in Retail Generation Sales
  (45.732.0)%
    
     
Retail Generation Revenues Decrease 
  (In millions) 
Residential $(166)
Commercial  (236)
Industrial  (182)
    
Decrease in Retail Generation Revenues
 $(584)
    
Wholesale generation revenues increased $4 million primarily due to an increase in sales to FES from OE’s leasehold interests in Perry Unit 1 and Beaver Valley Unit 2, partially offset by lower unit prices.
Distribution revenues decreased $1 million in the first nine months of 2010, compared to the same period in 2009, due to lower commercial and industrial revenues, partially offset by higher residential revenues. Commercial and industrial revenues were primarily impacted by lower average unit prices, resulting from lower transmission rates in 2010. Residential distribution revenues were higher due to higher average unit prices resulting from the 2009 ESP and higher KWH deliveries resulting from the warmer conditions described above. Increased industrial deliveries were the result of an increase in KWH deliveries to major steel customers (42%) and automotive customers (25%), reflecting improving economic conditions.

102

Changes in distribution KWH deliveries and revenues in the first nine months of 2010, compared to the same period in 2009, are summarized in the following tables:
Distribution KWH SalesIncrease
Residential6.3%
Commercial2.1%
Industrial10.6%
Increase in Distribution Deliveries
6.2%
        
 Increase 
Distribution Revenues (Decrease) 
Retail Generation Revenues Decrease 
 (In millions)  (In millions) 
Residential $27  $(85)
Commercial  (9)  (30)
Industrial  (19)  (12)
      
Net Decrease in Distribution Revenues
 $(1)
Decrease in Retail Generation Revenues
 $(127)
      
Expenses
Total expenses decreased $674$108 million in the first ninethree months of 2010, from2011, compared to the same period of 2009.2010. The following table presents changes from the prior period by expense category:
        
 Increase  Increase 
Expenses - Changes (Decrease) 
Expenses — Changes (Decrease) 
 (In millions)  (In millions) 
Purchased power costs $(564) $(94)
Other operating expenses  (100) 13 
Amortization of regulatory assets, net  (11)  (29)
General taxes 1  2 
      
Net Decrease in Expenses
 $(674) $(108)
      
Purchased power costs decreased in the first ninethree months of 2010,2011, compared to the same period of 2009,2010, primarily due to lower KWH purchases resulting from reduced generation sales requirements from increased customer shopping in the first ninethree months of 2010 and slightly2011 coupled with lower unit costs. The decreaseincrease in other operating costs for the first ninethree months of 2010,2011 was primarily due to lower MISO transmission expenses ($48 million) (assumed by third party suppliers beginning June 1, 2009) and lower costs associated with regulatory obligations for economic development and energy efficiency programs under OE’s 2009 ESP ($18 million).the 2011 Beaver Valley Unit 2 refueling outage that were absent in 2010. The amortization of regulatory assets decreased primarily due to lower MISO transmission cost amortization, partially offset by the recovery of certain regulatory assets.
Other Expense
Other expense increased $21 millionhigher deferred residential generation credits in the first nine months of 2010, compared to the same period of 2009, primarily due to lower nuclear decommissioning trust investment income.2011.

 

103121

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
CEI is a wholly owned electric utility subsidiary of FirstEnergy. CEI conducts business in northeastern Ohio, providing regulated electric distribution services. CEI also procures generation services for those customers electing to retain CEI as their power supplier.
For additional information with respect to CEI, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Earnings available to parent increaseddecreased by $93$1 million in the first ninethree months of 2010,2011, compared to the same period of 2009.2010. The increasedecrease in earnings was primarily due to the absence in 2010 of one-time regulatory charges recognized in 2009, and decreasedlower revenues, partially offset by lower purchased power and other operating costs, partially offset by decreased revenues and deferredamortization of regulatory assets.
Revenues
Revenues decreased $406$105 million, or 30%32%, in the first ninethree months of 2010,2011, compared to the same period of 2009,2010, due to decreasedlower retail generation and distribution revenues.
Distribution revenues decreased $76$5 million in the first ninethree months of 2010,2011, compared to the same period of 2009,2010, due to lower average unit prices for allthe industrial and residential customer classes offset by increased KWH deliveries inacross all sectors. The lower average unit prices were the result of lowerthe absence of transition ratescharges in 2010.2011. Higher KWH deliveries in the residential deliveries resulted fromclass were influenced by increased weather-related usage in the first ninethree months of 2010,2011, reflecting a 73%10% increase in coolingheating degree days. Increased industrial deliveries were the result of an increasedays in KWH deliveries to major steel customers (168%) and automotive customers (12%), reflecting improving economic conditions.CEI’s service territory.
Changes in distribution KWH deliveries and revenues in the first ninethree months of 2010,2011, compared to the same period of 2009,2010, are summarized in the following tables:
     
Distribution KWH SalesDeliveries Increase 
     
Residential  7.32.3%
Commercial  2.43.1%
Industrial  14.40.9%
    
Increase in Distribution Deliveries
  8.82.1%
    
    
     Increase 
Distribution Revenues Decrease  (Decrease) 
 (In millions)  (In millions) 
Residential $—  $— 
Commercial  (29) 7 
Industrial  (47)  (12)
      
Decrease in Distribution Revenues
 $(76)
Net Decrease in Distribution Revenues
 $(5)
      

122

Retail generation revenues decreased $321$101 million in the first ninethree months of 2010,2011, compared to the same period of 2009,2010, primarily due to lower KWH sales and lower average unit prices across all customer classes. Retail generation obligations are attributable to non-shopping customers and are procured through full-requirements auctions. CEI defers the difference between retail generation revenues and costs, resulting in no material effect to current period earnings. Reduced KWH sales were primarily the result of increased customer shopping in the first ninethree months of 2010. That condition is expected to continue to impact the comparative sales levels for the remainder of 2010. Lower KWH sales to residential customers were2011, partially offset by increasedhigher residential KWH deliveries resulting from the warmercolder weather conditions described above. Decreased volumes were partially offset by higherconditions. Lower average unit prices in allthe residential customer classes. Retail generation prices increased in 2010 as aclass were the result of the CBP auctiongeneration credits in place for the service period beginning June 1, 2009.2011.

104

Changes in retail generation sales and revenues in the first ninethree months of 2010,2011, compared to the same period of 2009,2010, are summarized in the following tables:
     
Retail Generation KWH Sales Decrease 
     
Residential  (51.748.4)%
Commercial  (69.448.3)%
Industrial  (47.462.8)%
    
Decrease in Retail Generation Sales
  (54.253.3)%
    
        
Retail Generation Revenues Decrease  Decrease 
 (In millions)  (In millions) 
Residential $(78) $(46)
Commercial  (126)  (29)
Industrial  (117)  (26)
      
Decrease in Retail Generation Revenues
 $(321) $(101)
      
Expenses
Total expenses decreased $561$98 million in the first ninethree months of 2010,2011, compared to the same period of 2009.2010. The following table presents the change from the prior period by expense category:
        
 Increase  Increase 
Expenses - Changes (Decrease) 
Expenses — Changes (Decrease) 
 (In millions)  (In millions) 
Purchased power costs $(441) $(82)
Other operating costs  (45) 4 
Amortization of regulatory assets, net  (205)  (22)
Deferral of new regulatory assets 135 
General taxes  (5) 2 
      
Net Decrease in Expenses
 $(561) $(98)
      
Purchased power costs decreased in the first ninethree months of 2010, primarily2011 due to lower KWH purchases resulting from reduced sales requirements as discussed above.in the first three months of 2011. Other operating costs decreasedexpenses increased due to lower transmission expenses (assumed2011 inventory valuation adjustments. Decreased amortization of regulatory assets was primarily due to completion of transition cost recovery at the end of 2010 and 2011 and deferred residential generation credits, partially offset by third party suppliers beginning June 1, 2009), labor and employee benefit expensesincreased recovery of non-residential distribution deferrals and the absence in 2010 of $12 million of costs incurreddeferred renewable energy credit expenses. General taxes increased in the first ninethree months of 2009 associated with regulatory obligations for economic development and energy efficiency programs. Decreased amortization of regulatory assets was due primarily to the 2009 impairment of CEI’s Extended RTC regulatory asset of $216 million in accordance with the PUCO-approved ESP. A decrease in the deferral of new regulatory assets was primarily2011 due to CEI’s contemporaneous recovery of purchased power costsincreased property taxes in 2010. General taxes decreased in the first nine months of 2010, primarily due to a 2010 favorable tax settlement in Ohio.
Other Expense
Other expense increased $4 million in the first nine months of 2010, compared to the same period of 2009 due primarily to lower investment income.2011.

 

105123

THE TOLEDO EDISON COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
TE is a wholly owned electric utility subsidiary of FirstEnergy. TE conducts business in northwestern Ohio, providing regulated electric distribution services. TE also procures generation services for those customers electing to retain TE as their power supplier.
For additional information with respect to TE, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Earnings available to parent increaseddecreased by $13$2 million in the first ninethree months of 2010,2011, compared to the same period of 2009.2010. The increase wasdecrease primarily due to decreased net amortization of regulatory assets, purchased powerresulted from lower revenues and higher other operating costs, partially offset by an increase in interest expenselower purchased power costs and decreases in revenues and investment income.deferral of regulatory assets.
Revenues
Revenues decreased $287$19 million, or 42%14%, in the first ninethree months of 2010,2011, compared to the same period of 2009, primarily2010, due to lowera decrease in retail generation and distribution revenues, partially offset by an increase inhigher distribution revenues and wholesale generation revenues.
Distribution revenues decreased $22increased $2 million in the first ninethree months of 2010,2011, compared to the same period of 2009, primarily2010, due to lower unit prices,higher residential and industrial revenues, partially offset by increasedlower commercial revenues. Residential and industrial revenues were the result of higher average unit prices and higher KWH deliveries. The higher KWH deliveries to all customer classes. Lower unit prices are primarily due to lower transmission rates. Higher KWH deliveriesin the residential class were influenced by increased weather-related usage in the first ninethree months of 2010,2011, reflecting an 84%a 9% increase in coolingheating degree days in TE’s service territory. Increased industrial deliveriesCommercial revenues were the result of an increase inimpacted by lower KWH deliveries to major automotive customers (29%) and steel customers (27%), reflecting improving economic conditions.lower average unit prices.
Changes in distribution KWH deliveries and revenues in the first ninethree months of 2010,2011, compared to the same period of 2009,2010, are summarized in the following tables:
     
Distribution KWH Sales Increase
Distribution KWH Deliveries(Decrease) 
     
Residential  9.83.6%
Commercial  2.2(2.3)%
Industrial  15.55.3%
    
Net Increase in Distribution Deliveries
  10.33.3%
    
        
 Increase  Increase 
Distribution Revenues (Decrease)  (Decrease) 
 (In millions)  (In millions) 
Residential $2  $2 
Commercial  (7)  (1)
Industrial  (17) 1 
      
Net Decrease in Distribution Revenues
 $(22)
Net Increase in Distribution Revenues
 $2 
      
Retail generation revenues decreased $282$25 million in the first ninethree months of 2010,2011, compared to the same period of 2009, primarily2010, due to lower KWH sales acrossto all customer classes and lower unit prices to residential and industrial customers. Retail generation obligations are attributable to non-shopping customers and are procured through full-requirements auctions. TE defers the difference between retail generation revenues and costs, resulting in no material effect to current period earnings. Lower KWH sales to all customer classes were primarily the result of a 59% increase inincreased customer shopping, in the first nine months of 2010. That condition is expected to continue to impact the comparative sales levels for the remainder of 2010. Lower unit prices for industrial customers were primarily due to the absence of TE’s fuel cost recovery and rate stabilization riders that were effective from January through May 2009, partially offset by increased generation prices resulting fromweather-related usage in the CBP auction, effective June 1, 2009.first three months of 2011, as described above.

 

106124

Changes in retail generation KWH sales and revenues in the first ninethree months of 2010,2011, compared to the same period of 2009,2010, are summarized in the following tables:
     
Retail Generation KWH Sales Decrease 
     
Residential  (45.128.5)%
Commercial  (72.549.5)%
Industrial  (59.413.1)%
    
Decrease in Retail Generation Sales
  (59.024.0)%
    
        
Retail Generation Revenues Decrease  Decrease 
 (In millions)  (In millions) 
Residential $(57) $(10)
Commercial  (104)  (6)
Industrial  (121)  (9)
      
Decrease in Retail Generation Revenues
 $(282) $(25)
      
Wholesale revenues increased $14$3 million in the first ninethree months of 2010,2011, compared to the same period of 2009,2010, primarily due to higher revenues from sales to NGC from TE’s leasehold interest in Beaver Valley Unit 2.
Expenses
Total expenses decreased $328$15 million in the first ninethree months of 2010,2011, compared to the same period of 2009.2010. The following table presents changes from the prior period by expense category:
        
 Increase  Increase 
Expenses - Changes (Decrease) 
Expenses — Changes (Decrease) 
 (In millions)  (In millions) 
Purchased power costs $(263) $(24)
Other operating expenses  (31) 11 
Provision for depreciation 1 
Amortization (deferral) of regulatory assets, net  (35)
Deferral of regulatory assets, net  (3)
General Taxes 1 
      
Net Decrease in Expenses
 $(328) $(15)
      
Purchased power costs decreased in the first ninethree months of 2010,2011, compared to the same period of 2009,2010, due to lower volume as a resultKWH purchases resulting from reduced generation sales requirements in the first three months of decreased KWH sales requirements. Other2011 coupled with lower unit costs. The increase in other operating costs decreasedfor the first three months of 2011 was primarily due to reduced transmission expense (assumed by third party suppliers beginning June 1, 2009), lower costsexpenses associated with regulatory obligations for economic developmentthe 2011 Beaver Valley Unit 2 refueling outage that were absent in 2010 and energy efficiency programs and decreased laborhigher storm restoration expenses. The amortizationdeferral of regulatory assets decreased primarilyincreased due to higher PUCO-approved cost deferrals and lower MISO transmission cost amortization in the first ninethree months of 2010,2011, compared to the same period of 2009.
Other Expense
Other expense increased $17 million in the first nine months of 2010, compared to the same period of 2009, primarily due to higher interest expense associated with the April 2009 issuance of $300 million senior secured notes and lower nuclear decommissioning trust investment income.2010.

 

107125

JERSEY CENTRAL POWER & LIGHT COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
JCP&L is a wholly owned, electric utility subsidiary of FirstEnergy. JCP&L conducts business in New Jersey, providing regulated electric transmission and distribution services. JCP&L also procures generation services for franchise customers electing to retain JCP&L as their power supplier. JCP&L procures electric supply to serve its BGS customers through a statewide auction process approved by the NJBPU.
For additional information with respect to JCP&L, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Market Risk Information, Credit Risk, Outlook, Regulatory Matters, Environmental Matters, Other Legal Proceedings and New Accounting Standards and Interpretations.
Results of Operations
Net income increaseddecreased by $34$10 million in the first ninethree months of 2010,2011, compared to the same period of 2009.2010. The increasedecrease was primarily due to higherlower revenues lower purchased power costs and decreasedincreased net amortization of regulatory assets, partially offset by increasedlower purchased power costs and other operating costs.
Revenues
In the first ninethree months of 2010,2011, revenues increased $43decreased $57 million, or 2%8%, compared to the same period of 2009.2010. The increasedecrease in revenues iswas primarily due to higherlower distribution and retail generation revenues, partially offset by an increase in wholesale generation and other revenues, partially offset by a decrease in retail generation revenues.
Distribution revenues increased $63decreased $17 million in the first ninethree months of 2010,2011, compared to the same period of 2009,2010, primarily due to a NJBPU-approved rate adjustment which became effective March 1, 2011 for all customer classes, partially offset by higher KWH deliveries in all customer classes. Increased usage was due to warmer weather and improved economic conditionsthe residential class resulting from a 6% increase in JCP&L’s service territory. Decreased composite unit prices in the commercial and industrial classes partially offset the increased volume.heating degree days.
Changes in distribution KWH deliveries and revenues in the first ninethree months of 20102011 compared to the same period of 2009 are summarized in the following tables:
Distribution KWH SalesIncrease
Residential10.6%
Commercial2.9%
Industrial3.0%
Increase in Distribution Deliveries
6.3%
     
Distribution Revenues Increase 
  (In millions) 
Residential $58 
Commercial  5 
Industrial  — 
    
Increase in Distribution Revenues
 $63 
    
Retail generation revenues decreased $54 million due to lower retail generation KWH sales in the commercial and industrial classes, partially offset by higher KWH sales in the residential class. Lower sales to the commercial and industrial classes were primarily due to an increase in the number of shopping customers. Higher KWH sales to the residential class reflected increased weather-related usage resulting from a 60% increase in cooling degree days during the first nine months of 2010.

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Changes in retail generation KWH sales and revenues in the first nine months of 2010 compared to the same period of 2009, are summarized in the following tables:
     
  Increase 
Retail GenerationDistribution KWH SalesDeliveries (Decrease) 
     
Residential  10.11.4%
Commercial  (27.73.4)%
Industrial  (21.42.0)%
    
Net Decrease in Retail Generation SalesDistribution Deliveries
  (5.01.1)%
    
        
 Increase 
Retail Generation Revenues (Decrease) 
Distribution Revenues Decrease 
 (In millions)  (In millions) 
Residential $81  $(5)
Commercial  (127)  (10)
Industrial  (8)  (2)
      
Net Decrease in Retail Generation Revenues
 $(54)
Decrease in Distribution Revenues
 $(17)
      
WholesaleRetail generation revenues increased $22decreased $47 million due to lower retail generation KWH sales in all customer classes. Retail generation obligations are attributable to non-shopping customers and are procured through full-requirements auctions. JCP&L defers the difference between retail generation revenues and costs, resulting in no material effect to current period earnings. These lower sales were primarily due to an increase in customer shopping.

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Changes in retail generation KWH sales and revenues in the first ninethree months of 2010,2011, compared to the same period of 2009, due primarily to higher wholesale energy prices.2010, are summarized in the following tables:
Other
Retail Generation KWH SalesDecrease
Residential(7.5)%
Commercial(26.4)%
Industrial(23.1)%
Decrease in Retail Generation Sales
(13.7)%
     
Retail Generation Revenues Decrease 
  (In millions) 
Residential $(15)
Commercial  (29)
Industrial  (3)
    
Decrease in Retail Generation Revenues
 $(47)
    
Wholesale generation revenues increased $8$3 million in the first ninethree months of 2010,2011, compared to the same period of 2009,2010, due primarily to an increase in sales volumes.
Other revenues increased $4 million in the first three months of 2011, compared to the same period of 2010, primarily due to an increase in transition bond revenues as a result of higher KWH deliveries in all customer classes.to residential customers.
Expenses
Total expenses decreased $18$43 million in the first ninethree months of 2010,2011, compared to the same period of 2009.2010. The following table presents changes from the prior period by expense category:
        
 Increase  Increase 
Expenses - Changes (Decrease) 
Expenses — Changes (Decrease) 
 (In millions)  (In millions) 
Purchased power costs $(33) $(44)
Other operating costs 19   (9)
Provision for depreciation 5   (3)
Amortization of regulatory assets, net  (12) 12 
General taxes 3  1 
      
Net Decrease in Expenses
 $(18) $(43)
      
Purchased power costs decreased in the first ninethree months of 20102011 primarily due to the lower retail generation KWH sales requirements.requirements from reduced sales. Other operating costs increaseddecreased in the first ninethree months of 20102011 primarily due to majorlower storm clean uprestoration costs, in JCP&L’s service territory, partially offset by a favorable settlement of $7 million for collective bargaining agreement recognized in the second quarter of 2010. Depreciation expense increased due to an increase in depreciable property since the third quarter of 2009.inventory valuation adjustments. The amortization of regulatory assets decreasedincreased primarily due to lower storm cost deferrals and the write-off of nonrecoverable NUG costs, partially offset by lower purchased power deferrals in the first nine monthsquarter of 2010 primarily due to the deferral of storm costs.2011.

 

109127

METROPOLITAN EDISON COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
Met-Ed is a wholly owned electric utility subsidiary of FirstEnergy. Met-Ed conducts business in eastern Pennsylvania, providing regulated electric transmission and distribution services. Met-Ed also procures generation service for those customers electing to retain Met-Ed as their power supplier. In 2011, Met-Ed has a wholesaleprocures power sales agreement with FES, to supply allunder its Default Service Plan (DSP) in which full requirements products (energy, capacity, ancillary services, and applicable transmission services) are procured through descending clock auctions.
As authorized by Met-Ed’s Board of Directors, Met-Ed repurchased 118,595 shares of its energy requirements at fixed prices through the end of 2010.common stock from its parent, FirstEnergy, for $150 million on January 28, 2011.
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, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Market Risk Information, Credit Risk, Outlook, Capital Resources and Liquidity, Regulatory Matters, Environmental Matters, Other Legal Proceedings and New Accounting Standards and Interpretations.
Results of Operations
Net income increased by $6$10 million in the first ninethree months of 2010,2011, compared to the same period of 2009.2010. The increase was primarily due to increased revenuesdecreased purchased power, other operating expenses and decreased amortization of net regulatory assets, partially offset by increased purchased power and other operating expenses.decreased revenues.
Revenues
Revenue increased $147decreased $116 million, or 12%24%, in the first ninethree months of 20102011 compared to the same period of 2009,2010, reflecting higherlower distribution, wholesale generation and generationtransmission revenues, partially offset by a decreasean increase in transmissionretail generation revenues.
Distribution revenues increased $82decreased $72 million in the first ninethree months of 2010,2011, compared to the same period of 2009,2010, primarily due to higherlower rates resulting from the annual update to Met-Ed’s TSC rider effective June 1, 2010, partially offset by lower CTC rates forDSP that began in 2011 that eliminated the residential class.transmission component from the distribution rate. Higher KWH deliveries to industrial customers were due to improving economic conditions in Met-Ed’s service territory. Higher residential and commercial KWH deliveries reflect increased weather-related usage due to a 59%an 8% increase in coolingheating degree days in the first ninethree months of 2010, partially offset by an 11% decrease in heating degree days for2011, compared to the same period.period in 2010.
Changes in distribution KWH deliveries and revenues in the first ninethree months of 2010,2011, compared to the same period of 2009,2010, are summarized in the following tables:
     
Distribution KWH Deliveries Increase 
     
Residential  5.03.4%
Commercial  4.42.5%
Industrial  4.05.8%
    
Increase in Distribution Deliveries
  4.64.1%
    
        
Distribution Revenues Increase  Decrease 
 (In millions)  (In millions) 
Residential $40  $(29)
Commercial 27   (17)
Industrial 15   (26)
      
Increase in Distribution Revenues
 $82 
Decrease in Distribution Revenues
 $(72)
      
Retail generation revenues increased $36$18 million in the first ninethree months of 2010,2011 compared to the same period of 2009, due to higher composite unit prices in the residential and commercial customer classes and higher KWH sales to all customer classes. The higher unit prices were primarily2010, due to an increase in generation rates from the generation rate,auctions and now including transmission services in the rates under the DSP effective January 1, 2010.2011. The DSP resulted in higher composite unit prices across all customer classes. Higher KWH sales to residential and commercial customers increasedwere primarily due to weather-related usage as described above. Increased customer shopping in the commercial and industrial classes partially offset the higherof 36% and 81%, respectively, reduced KWH sales into these classes. Retail generation obligations are attributable to non-shopping customers and are procured through full-requirements auctions. Met-Ed defers the difference between retail generation revenues and costs, resulting in no material effect to current period earnings.

 

110128

Changes in retail generation KWH sales and revenues in the first ninethree months of 2010,2011, compared to the same period of 2009,2010, are summarized in the following tables:
     
Increase
Retail Generation KWH Sales Increase(Decrease) 
     
Residential  5.02.7%
Commercial  2.8(34.1)%
Industrial  1.1(80.0)%
    
IncreaseNet Decrease in Retail Generation Sales
  3.3(34.5)%
    
    
     Increase 
Retail Generation Revenues Increase  (Decrease) 
 (In millions)  (In millions) 
Residential $30  $53 
Commercial 5  3 
Industrial 1   (38)
      
Increase in Retail Generation Revenues
 $36 
Net Increase in Retail Generation Revenues
 $18 
      
Wholesale revenues increased $42decreased $54 million in the first ninethree months of 20102011 compared to the same period of 2009,2010, primarily reflecting higher PJMdue to Met-Ed ending certain capacity prices.purchase for resale contracts.
Transmission revenues decreased $13$8 million in the first ninethree months of 20102011 compared to the same period of 20092010 primarily due to decreased Financial Transmission RightsFTR revenues. Met-Ed defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.
Expenses
Total expenses increased $130decreased $121 million in the first ninethree months of 20102011 compared to the same period of 2009.2010. The following table presents changes from the prior year by expense category:
        
 Increase 
Expenses - Changes (Decrease) 
Expenses — Changes Decrease 
 (In millions)  (In millions) 
Purchased power costs $78  $(50)
Other operating costs 112   (54)
Provision for depreciation 1 
Amortization of regulatory assets, net  (61)  (17)
      
Net Increase in Expenses
 $130 
Decrease in Expenses
 $(121)
      
Purchased power costs increased $78decreased $50 million in the first ninethree months of 20102011 due to an increasea decrease in unit costs and increased KWH purchased to source increased generation sales requirements.requirements, partially offset by higher unit costs. Other operating costs increased $112decreased $54 million in the first ninethree months of 20102011 compared to the same period in 20092010 primarily due to higherlower transmission congestion and transmission loss expenses (see reference to deferral accounting above). Depreciation expense increased $1 million due to an increase in depreciable property since September of 2009. The amortization of regulatory assets decreased $61$17 million in the first ninethree months of 20102011 primarily due to higher PJM deferrals resulting from increasedthe termination of transmission costs and reduced amortization from decreasing asset balances.transition tariff riders at the end of 2010.
Other Expense
In the first ninethree months of 2010,2011, interest income decreased $4 million due to reduced CTC stranded asset balances.balances compared to the same period of 2010.

 

111129

PENNSYLVANIA ELECTRIC COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts business in northern and south central Pennsylvania, providing regulated transmission and distribution services. Penelec also procures generation servicesservice for those customers electing to retain Penelec as their power supplier. Beginning in 2011, Penelec has a wholesaleprocures power sales agreement with FES, to supply all ofunder its energyDefault Service Plan (DSP) in which full requirements at fixed pricesproducts (energy, capacity, ancillary services, and applicable transmission services) are procured through the end of 2010.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: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk, Outlook, Regulatory Matters, Environmental Matters, Other Legal Proceedings and New Accounting Standards and Interpretations.
Results of Operations
Net income increased slightly in the first three months of 2011, compared to the same period of 2010. The increase was primarily due to lower purchased power and other operating costs, partially offset by lower revenues, net amortization of regulatory assets and higher general taxes.
Revenues
Revenue decreased $79 million, or 19.5%, in the first three months of 2011 compared to the same period of 2010. The decrease in revenue was primarily due to lower retail and wholesale generation revenues and lower transmission revenues, partially offset by higher distribution revenues.
Distribution revenues increased by $1 million in the first ninethree months of 2010,2011, compared to the same period of 2009. The increase was2010, primarily due to higher revenues and net deferral of regulatory assets, partially offset by higher purchased power, other operating costs and interest expense.
Revenues
In the first nine months of 2010, revenues increased $84 million, or 7.8%, compared to the same period of 2009. Thean increase in revenue was primarily due to higher generation revenues, partially offset by lower distributionthe retail transition rates and transmission revenues.
Distribution revenues decreased by $2 million in the first nine months of 2010, compared to the same period of 2009, primarily due to a decrease in the CTC rate inenergy efficiency rates for all customer classes, partially offset by an increase in the universal service and energy efficiency rates for the residential customer class and increaseddecreased KWH sales in all customerthe residential and commercial classes.
Changes in distribution KWH deliveries and revenues in the first ninethree months of 2010,2011, compared to the same period of 2009,2010, are summarized in the following tables:
     
Increase
Distribution KWH Deliveries Increase(Decrease) 
     
Residential  4.6(0.2)%
Commercial  4.6(3.0)%
Industrial  6.310.0%
    
Net Increase in Distribution Deliveries
  5.13.1%
    
        
 Increase  Increase 
Distribution Revenues (Decrease)  (Decrease) 
 (In millions)  (In millions) 
Residential $19  $3 
Commercial  (12)  (5)
Industrial  (9) 3 
      
Net Decrease in Distribution Revenues
 $(2)
Net Increase in Distribution Revenues
 $1 
      
Retail generation revenues increased $66decreased $22 million in the first ninethree months of 2010,2011, compared to the same period of 2009,2010, primarily due to higher unit prices andlower KWH sales into all customer classes, partially offset by higher generation rates for all customer classes. The higher unit pricesRetail generation obligations are attributable to non-shopping customers and are procured through full-requirements auctions. Penelec defers the difference between retail generation revenues and costs, resulting in no material effect to current period earnings. Lower sales to all customer classes were primarily due to an increase in customer shopping following the expiration of generation rate caps at the end of 2010. Higher generation rates reflect the inclusion of transmission services in generation rates under the DSP, effective January 1, 2010. Higher KWH sales to industrial customers were due to improved economic conditions in Penelec’s service territory. Higher KWH sales to residential and commercial customers increased primarily due to weather-related usage, reflecting a 94% increase in cooling degree days in the first nine months of 2010, partially offset by a 10% decrease in heating degree days for the same period.2011.

 

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Changes in retail generation KWH sales and revenues in the first ninethree months of 20102011, compared to the same period of 20092010, are summarized in the following tables:
     
Retail Generation KWH Sales IncreaseDecrease 
     
Residential  4.6(0.4)%
Commercial  4.3(38.3)%
Industrial  6.9(78.5)%
    
IncreaseDecrease in Retail Generation Sales
  5.1(39.1)%
    
    
     Increase 
Retail Generation Revenues Increase  (Decrease) 
 (In millions)  (In millions)��
Residential $17  $31 
Commercial 26   (9)
Industrial 23   (44)
      
Increase in Retail Generation Revenues
 $66 
Net Decrease in Retail Generation Revenues
 $(22)
      
Wholesale generation revenues increased $39decreased $49 million in the first ninethree months of 2010,2011, compared to the same period of 2009,2010, due primarily to higherPenelec no longer purchasing non-NUG capacity for resale to the PJM capacity prices.market beginning in 2011.
Transmission revenues decreased by $13$8 million in the first ninethree months of 2010,2011, compared to the same period of 2009,2010, primarily due to lower Financial Transmission Rights revenue.revenues. Penelec defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.
Expenses
Total expenses increaseddecreased by $71$75 million in the first ninethree months of 2010,2011, as compared with the same period of 2009.2010. The following table presents changes from the prior periodyear by expense category:
     
  Increase 
Expenses - Changes (Decrease) 
  (In millions) 
Purchased power costs $111 
Other operating costs  27 
Provision for depreciation  1 
Amortization (deferral) of regulatory assets, net  (66)
General taxes  (2)
    
Net Increase in Expenses
 $71 
    
     
  Increase 
Expenses — Changes (Decrease) 
  (In millions) 
Purchased power costs $(71)
Other operating costs  (31)
Amortization of regulatory assets, net  23 
General taxes  4 
    
Net Decrease in Expenses
 $(75)
    
Purchased power costs increased $111decreased $71 million in the first ninethree months of 2010,2011, compared to the same period of 2009,2010, primarily due to an increase in unit costs and increaseddecreased KWH purchased to source increased generation sales requirements. Other operating costs increased $27decreased $31 million in the first ninethree months of 2010,2011, primarily due to higherlower transmission congestion and transmission loss expenses (see reference to deferral accounting above). The amortization (deferral) of net regulatory assets decreased $66increased $23 million in the first ninethree months of 2010,2011, primarily due to increased costreduced NUG deferrals resulting from higher transmission expenses and decreased amortizationas a result of regulatory assets resulting from lower CTC revenues.a NUG Rider implemented in January 2011. General taxes decreased $2increased $4 million primarily due to higher Pennsylvania Sales and Use Taxes and the absence of a favorable ruling on a property tax appeal in the first quarter of 2010.
Other Expense
In the first nine months of 2010, other expense increased $14 million primarily due to an increase in interest expense on long-term debt due to a $500 million debt issuance in September 2009.

 

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ITEM 3.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Risk Information” in Item 2 above.
ITEM 4.
ITEM 4. CONTROLS AND PROCEDURES
(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES — FIRSTENERGY
FirstEnergy’s management, with the participation of its chief executive officer and chief financial officer, have reviewed and evaluated the 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 15(d)-15(e), as of the end of the period covered by this report. Based on that evaluation, the chief executive officer and chief financial officer have concluded that the registrant’s disclosure controls and procedures were effective as of the end of the period covered by this report.
(b) CHANGES IN INTERNAL CONTROLSCONTROL OVER FINANCIAL REPORTING
During the quarter ended September 30, 2010,March 31, 2011, other than changes resulting from the Allegheny merger discussed below, there werehave been no changes in FirstEnergy’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrant’sFirstEnergy’s internal control over financial reporting.
ITEM 4T. CONTROLS AND PROCEDURES — FES, OE, CEI, TE, JCP&L, MET-ED AND PENELEC
(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
Each registrant’s management, withOn February 25, 2011, the participation of its chief executive officermerger between FirstEnergy and chief financial officer, have reviewed and evaluated the effectiveness of such registrant’s disclosure controls and procedures, as definedAllegheny closed. FirstEnergy is currently in the Securities Exchange Actprocess of 1934, as amended, Rules 13a-15(e)integrating Allegheny’s operations, processes, and 15(d)-15(e), as ofinternal controls. See Note 2 to the end ofconsolidated financial statements in Part I, Item I for additional information relating to the period covered by this report. Based on that evaluation, each registrant’s chief executive officer and chief financial officer have concluded that such registrant’s disclosure controls and procedures were effective as of the end of the period covered by this report.merger.

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(b) CHANGES IN INTERNAL CONTROLS
During the quarter ended September 30, 2010, there were no changes in the registrants’ internal control over financial reporting that has materially affected, or are reasonably likely to materially affect, the registrants’ internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1.
ITEM 1. LEGAL PROCEEDINGS
ICG Litigation
On December 28, 2006, AE Supply and MP filed a complaint in the Court of Common Pleas of Allegheny County, Pennsylvania against International Coal Group, Inc. (ICG), Anker West Virginia Mining Company, Inc. (Anker WV), and Anker Coal Group, Inc. (Anker Coal). Anker WV, now known as Wolf Mining Company, entered into a long term Coal Sales Agreement with AE Supply and MP for the supply of coal to the Harrison generating facility. Anker Coal, now known as Hunter Ridge Holdings Inc., guaranteed performance under the contract. 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 on January 10, 2011 through February 1, 2011. At trial, AE Supply and MP presented evidence that they have incurred damages for replacement coal purchased through the end of 2010 and will incur additional damages for future shortfalls. The total damages claimed were in excess of $150 million. 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, which may be challenged in post-trial filings and an appeal.
Additional Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 910 and 1011 of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
ITEM 1A.
ITEM 1A. RISK FACTORS
FirstEnergy’s Annual Report on Form 10-K for the year ended December 31, 2009,2010, includes a detailed discussion of its risk factors. There have been no material changes to theseIn connection with the recent acquisition of Allegheny and the current events in Japan, the information presented below updates and supplements the risk factors appearing in our annual Report on Form 10-K for the quarteryear ended September 30,December 31, 2010.
Potential NRC Regulation in Response to the Incident at Japan’s Fukushima Daiichi Nuclear Plant
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. It is also possible that the NRC could suspend or otherwise delay pending nuclear relicensing proceedings, including the Davis-Besse relicensing proceeding. FirstEnergy cannot currently estimate the impact of any such regulatory actions on its financial condition or results of operations.
Risks Associated With Our Recently Completed Merger
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 segments and the unregulated competitive segment. Our ability to achieve the anticipated benefits of the merger is subject to a number of uncertainties, including whether the business of Allegheny is integrated in an efficient and effective manner and maintenance of the current credit ratings of the combined company and its subsidiaries. Failure to achieve these anticipated benefits could result in increased costs, decreases in the amount of expected revenues generated by the combined company and diversion of management’s time and energy and could have an adverse effect on the combined company’s business, financial results and prospects.
As a Result of the Merger We Will be Subject to Business Uncertainties That Could Adversely Affect Our Financial Results.
Although we are taking steps designed to reduce any adverse effects, uncertainty about the effect of the merger with AE on employees and customers may have an adverse effect on us. Employee retention and recruitment may be particularly challenging, as employees and prospective employees may experience uncertainty about their future roles with the combined company. Despite our retention and recruiting efforts, key employees may 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. Additionally, customers, suppliers and others that deal with us may seek to change existing relationships.
Furthermore, 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. In each case, our business results could be affected.

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The Combined Company Will Have a Higher Percentage of Coal-Fired Generation Capacity Compared to FirstEnergy’s Previous Generation Mix. As a Result, FirstEnergy May Be Exposed to Greater Risk from Regulations of Coal and Coal Combustion By-Products Than it Faced Prior to the Merger
The combined company’s generation fleet has a higher percentage of coal-fired generation capacity compared to FirstEnergy’s previous generation mix. As a result, FirstEnergy’s exposure to new or changing legislation, regulation or other legal requirements related to greenhouse gas or other emissions may be increased compared to its previous exposure. Approximately 52% of FirstEnergy’s pre-merger generation fleet capacity was coal-fired, with the remainder being low-emitting natural gas, oil fired or non-emitting nuclear and pumped storage. Approximately 78% of Allegheny’s generation fleet capacity is coal-fired. Approximately 62% of the combined company’s 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 substances such as sulfur dioxide, nitrogen oxide and mercury. In addition, there are currently a number of federal, state and international initiatives under consideration to, among other things, require reductions in greenhouse gas emissions from power generation or other facilities and to regulate coal combustion by-products, such as coal ash, as hazardous waste. These legal requirements and initiatives could require substantial additional costs, extensive mitigation efforts and, in the case of greenhouse gas legislation, could raise uncertainty about the future viability of fossil fuels 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. FirstEnergy expects approximately 70% of its generation fleet to be non-emitting or low-emitting by the end of 2011. All of Allegheny’s supercritical coal-fired generation assets are scrubbed, and its generation portfolio also includes pumped storage and natural gas generation capacity. The combined company’s generation fleet nevertheless could face greater exposure to risks relating to the foregoing legal requirements than FirstEnergy’s pre-merger fleet due to the combined company’s increased percentage of coal-fired generation facilities.
ITEM 2.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
(c) FirstEnergy
The table below includes information on a monthly basis regarding purchases made by FirstEnergy of its common stock during the thirdfirst quarter of 2010.2011.
                
                 Period 
 Period  January February March First Quarter 
 July August September Third Quarter  
Total Number of Shares Purchased(a)
 38,180 43,103 460,312 541,595  32,053 543,138 1,344,212 1,919,403 
 
Average Price Paid per Share
 $36.41 $37.28 $36.76 $36.78  $38.36 $38.44 $37.55 $37.81 
 
Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs
 — — — —  — — — — 
 
Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
 — — — —  — — — — 
   
(a) Share amounts reflect purchases on the open market to satisfy FirstEnergy’s obligations to deliver common stock under itsfor some or all of the following: 2007 Incentive Compensation 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 upon exercise of stock options granted under the 2007 Incentive Compensation Plan and the Executive Deferred Compensation Plan.
ITEM 5. OTHER INFORMATION
Signal Peak and Global Rail Credit Facility
On October 22, 2010, FEV, WMB Loan Ventures LLC and WMB Loan Ventures II LLC, the entities that own mining and coal transportation operations near Roundup, Montana (Signal Peak and Global Rail) entered into a $350 million syndicated two-year senior secured term loan facility among the two limited liability companies that comprise Signal Peak and Global Rail, as borrowers Sovereign Bank, CoBank, Credit Agricole, U.S. Bank, BBVA Compass, Royal Bank of Canada, Fifth Third, Comerica Bank, CIBC Inc. and First Merit banks, as lenders, and Union Bank, N.A., as lender, administrative agent, collateral agent and syndication agent. FirstEnergy, together with WMB Loan Ventures LLC and WMB Loan Ventures II LLC, the entities that share ownership with FEV in the borrowers have provided a guaranty of the borrowers’ obligations under the facility. In addition, FEV and the other entities that directly own the equity interests in the borrowers have pledged those interests to the banks as collateral for the facility. The loan matures on October 22, 2012. The loan proceeds were used by the borrowers primarily to repay $258 million of notes payable to FirstEnergy, including $9 million of interest, and $63 million of bank loans that were scheduled to mature on November 16, 2010. Additional proceeds will be used for general company purposes, including an $11 million repayment of a third-party seller’s note maturing October 29, 2010.

 

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ITEM 5.
OTHER INFORMATION
Signal Peak Mine Safety
FirstEnergy, through its FEV wholly-owned subsidiary, has a 50% interest in Global Mining Group LLC, a joint venture that owns 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 facility contains customary representations, warranties, covenants and events of defaultsoperation of the borrowers,Mine is subject to regulation by the guarantorsFederal Mine Safety and Health Administration (MSHA) under the pledgorsFederal Mine Safety and the foregoing descriptionHealth Act of 1977 (Mine Act).
Section 1503 of the facility is qualified in its entirety by referenceDodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), which was enacted on July 21, 2010, contains new reporting requirements regarding mine safety, including, to the copyextent applicable, disclosing in periodic reports filed under the Securities Exchange Act of 1934 the receipt of certain notifications from the MSHA.
On November 19, 2010, Signal Peak received a letter from MSHA placing it on notice that the Mine has a potential pattern of violations of mandatory health or safety standards under Section 104(e) of the credit agreement, includingMine Act. If implemented, Section 104(e) requires all subsequent violations designated as Significant and Substantial be issued as closure orders with all persons withdrawn from the formsaffected area except those necessary to correct the violation. On March 16, 2011, Signal Peak Mine received a letter from MSHA indicating that the mine is no longer being considered for a pattern of potential violations notice.
Signal Peak received the guarantyfollowing notices of violation and pledge agreement attached as exhibits thereto, included withproposed assessments for the Mine under the Mine Act during the three months ended March 31, 2011:
     
  Signal 
  Peak 
Number of significant and substantial violations of mandatory health or safety standards under 104*  22 
Number of orders issued under 104(b)*  — 
Number of citations and orders for unwarrantable failure to comply with mandatory health or safety standards under 104(d)*  — 
Number of flagrant violations under 110(b)(2)*  — 
Number of imminent danger orders issued under 107(a)*  — 
MSHA written notices under Mine Act section 104(e)* of a pattern of violation of mandatory health or safety standards or of the potential to have such a pattern  — 
Pending Mine Safety Commission legal actions (including any contested citations issued)  13 
Number of mining related fatalities  — 
Total dollar value of proposed assessments $1,892 
*References to sections under Mine Act
The inclusion of this information in this report as Exhibit 10.3.is not an admission by FirstEnergy that it controls Signal Peak or that Signal Peak is FirstEnergy’s subsidiary for purposes of Section 1503 or for any other purpose,
More detailed information about the Mine, including safety-related data, can be found at MSHA’s website, www.MSHA.gov. Signal Peak operates the Mine under the MSHA identification number 2401950.

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ITEM 6.
ITEM 6. EXHIBITS
Exhibit Number
       
FirstEnergy
3.1Amendment to the Amended Articles of Incorporation of FirstEnergy Corp. dated as of February 25, 2011 (incorporated by reference to FirstEnergy’s Form 8-K filed February 25, 2011, Exhibit 3.1, File No. 21011)
      
   10.1  Amended FirstEnergy Corp. Deferred CompensationAllegheny Energy, Inc. 1998 Long-Term Incentive Plan for Outside Directors, amended and restated as of September 21, 2010.(incorporated by reference to FirstEnergy’s Form 8-K filed February 25, 2011, Exhibit 10.2, File No. 21011)
   10.2  Amended FirstEnergy Corp. Executive Deferred CompensationAllegheny Energy, Inc. 2008 Long-Term Incentive Plan amended and restated as of September 21, 2010.(incorporated by reference to FirstEnergy’s Form 8-K filed February 25, 2011, Exhibit 10.3, File No. 21011)
   10.3  Signal Peak CreditAllegheny 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)
10.4Allegheny 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)
10.5Amendment to FirstEnergy Corp. 2007 Incentive Compensation Plan, effective January 1, 2011
10.6Amendment to FirstEnergy Corp. Executive Deferred Compensation Plan, effective January 1, 2012
10.7Amendment to FirstEnergy Corp. Deferred Compensation Plan for Outside Directors, effective January 1, 2012
10.8Amendment to FirstEnergy Corp. Supplemental Executive Retirement Plan, effective January 1, 2012
10.9FirstEnergy Corp. Change in Control Severance Plan
10.10Amendment to Employment Agreement, including the forms of the guarantydated February 25, 2011, between FirstEnergy Service Company and pledge agreement attached as exhibits theretoGary R. Leidich
   12  Fixed charge ratios
   31.1  Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
   
31.2  Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
   32  Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
   
101* The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the period ended September 30, 2010,March 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 blocks of text and (v) document and entity information.
       
FES      
   1210.1  Fixed charge ratiosAsset Purchase Agreement dated as of March 11, 2011 by and between FirstEnergy Generation Corp. and American Municipal Power, Inc.
 31.1Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
31.2Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
32Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
OE      
   12  Fixed charge ratios
   
31.1  Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
   31.2  Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
   
32  Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
OE      
CEI      
   12  Fixed charge ratios
   
31.1  Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
   
31.2  Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
32Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
CEI
12Fixed charge ratios
31.1Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
31.2Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
   32  Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
       
TE      
   12  Fixed charge ratios
   
31.1  Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
   
31.2  Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
   32  Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
       

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JCP&L      
   12  Fixed charge ratios
   
31.1  Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
   31.2  Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
   
32  Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350

115

       
Met-Ed      
   12  Fixed charge ratios
   
31.1  Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
   
31.2  Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
   32  Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
       
Penelec      
   12  Fixed charge ratios
   
31.1  Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
   
31.2
  Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
   32  Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
   
* 
Users of these data are advised pursuant to Rule 401 of Regulation S-T that the financial information contained in the XBRL-Related Documents is unaudited and, as a result, investors should not rely on the XBRL-Related Documents in making investment decisions. Furthermore, users of these data are advised in accordance with Rule 406T of Regulation S-T promulgated by the Securities and Exchange Commission that this Interactive Data File is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.
Pursuant to reporting requirements of respective financings, FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec are required to file fixed charge ratios as an exhibit to this Form 10-Q.
Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed nor Penelec have filed as an exhibit to this Form 10-Q any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of its respective total assets, but each hereby agrees to furnish to the SEC on request any such documents.

 

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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
October 26, 2010May 3, 2011
FIRSTENERGY CORP.
Registrant
     
 
FIRSTENERGY CORP.
Registrant

FIRSTENERGY SOLUTIONS CORP.
Registrant

OHIO EDISON COMPANY
Registrant

THE CLEVELAND ELECTRIC
ILLUMINATING COMPANY
Registrant

THE TOLEDO EDISON COMPANY
Registrant

METROPOLITAN EDISON COMPANY
Registrant

PENNSYLVANIA ELECTRIC COMPANY
Registrant		  
/s/ Harvey L. Wagner  
Harvey L. Wagner 
Vice President, Controller
and Chief Accounting Officer 
     
 OHIO EDISON COMPANY
Registrant
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
Registrant
THE TOLEDO EDISON COMPANY
Registrant
METROPOLITAN EDISON COMPANY
Registrant
PENNSYLVANIA ELECTRIC COMPANY
Registrant
/s/ Harvey L. Wagner
Harvey L. Wagner
Vice President, Controller
and Chief Accounting Officer
JERSEY CENTRAL POWER & LIGHT COMPANY
Registrant
  
 /s/ K. Jon Taylor
K. Jon Taylor		  
 K. Jon TaylorController  
 Controller
(Principal Accounting Officer)  

 

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