Form 10-Q
Table of Contents

 
 
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, 2010
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.
     
Yes þ No o
 
FirstEnergy Corp., FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
     
Yes þ No o
  FirstEnergy Corp.
 
   
Yes o No o
 
FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company, and Pennsylvania Electric Company
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
     
Large Accelerated Filer þ
  FirstEnergy Corp.
 
   
Accelerated Filer o
  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 Company o
  N/A
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
     
Yes o No þ
 
FirstEnergy Corp., FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:
         
    OUTSTANDING  
CLASS   AS OF OCTOBER 22, 2010  
FirstEnergy Corp., $10 par value
    304,835,407  
FirstEnergy Solutions Corp., no par value
    7  
Ohio Edison Company, no par value
    60  
The Cleveland Electric Illuminating Company, no par value
    67,930,743  
The Toledo Edison Company, $5 par value
    29,402,054  
Jersey Central Power & Light Company, $10 par value
    13,628,447  
Metropolitan Edison Company, no par value
    859,500  
Pennsylvania Electric Company, $20 par value
    4,427,577  
FirstEnergy Corp. is the sole holder of FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company common stock.
 
 

 

 


Table of Contents

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 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.

 

 


Table of Contents

Forward-Looking Statements: This Form 10-Q includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements include declarations regarding management’s intents, beliefs and current expectations. These statements typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” “believe,” “estimate” and similar words. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements.
Actual results may differ materially due to:
   
The speed and nature of increased competition in the electric utility industry and legislative and regulatory changes affecting how generation rates will be determined following the expiration of existing rate plans in Pennsylvania.
   
The impact of the regulatory process on the pending matters in Ohio, Pennsylvania and New Jersey.
   
Business and regulatory impacts from ATSI’s realignment into PJM.
   
Economic or weather conditions affecting future sales and margins.
   
Changes in markets for energy services.
   
Changing energy and commodity market prices and availability.
   
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 increased costs.
   
Operation and maintenance costs being higher than anticipated.
   
Other legislative and regulatory changes, and revised environmental requirements, including possible GHG emission and coal combustion residual regulations.
   
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.
   
The uncertainty of the timing and amounts of the capital expenditures needed to, among other things, implement the Air Quality Compliance Plan (including that such amounts could be higher than anticipated or that certain generating units may need to be shut down) or levels of emission reductions related to the Consent Decree resolving the NSR litigation or other potential similar regulatory initiatives or actions.
   
Adverse regulatory or legal decisions and outcomes (including, but not limited to, the revocation of necessary licenses or operating permits and oversight) by the NRC.
   
Ultimate resolution of Met-Ed’s and Penelec’s TSC filings with the PPUC.
   
The continuing availability of generating units and their ability to operate at or near full capacity.
   
The ability to comply with applicable state and federal reliability standards and energy efficiency mandates.
   
The ability to accomplish or realize anticipated benefits from strategic goals (including employee workforce initiatives).
   
The ability to improve electric commodity margins and to experience growth in the distribution business.
   
The changing market conditions that could affect the value of assets held in the registrants’ nuclear decommissioning trusts, pension trusts and other trust funds, and cause FirstEnergy to make additional contributions sooner, or in amounts that are larger than currently anticipated.
   
The ability to access the public securities and other capital and credit markets in accordance with FirstEnergy’s financing plan and the cost of such capital.
   
Changes in general economic conditions affecting the registrants.
   
The state of the capital and credit markets affecting the registrants.
   
Interest rates and any actions taken by credit rating agencies that could negatively affect the registrants’ access to financing or their costs and increase requirements to post additional collateral to support outstanding commodity positions, LOCs and other financial guarantees.
   
The state of the national and regional economies and associated impacts on the registrants’ major industrial and commercial customers.
   
Issues concerning the soundness of financial institutions and counterparties with which the registrants do business.
   
The expected timing and likelihood of completion of the proposed merger with Allegheny Energy, Inc., including the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the proposed merger that could reduce anticipated benefits or cause the parties to abandon the merger, the diversion of management’s time and attention from FirstEnergy’s ongoing business during this time period, the ability to maintain relationships with customers, employees or suppliers as well as the ability to successfully integrate the businesses and realize cost savings and any other synergies and the risk that the credit ratings of the combined company or its subsidiaries may be different from what the companies expect.
   
The risks and other factors discussed from time to time in the registrants’ SEC filings, and other similar factors.
The foregoing review of factors should not be construed as exhaustive. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor assess the impact of any such factor on the registrants’ business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. A security rating is not a recommendation to buy, sell or hold securities that may be subject to revision or withdrawal at any time by the assigning rating organization. Each rating should be evaluated independently of any other rating. The registrants expressly disclaim any current intention to update any forward-looking statements contained herein as a result of new information, future events or otherwise.

 

 


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TABLE OF CONTENTS
         
    Page  
 
       
    iii-v  
 
       
       
 
       
FirstEnergy Corp.
       
 
       
    1  
 
       
    2  
 
       
    3  
 
       
    4  
 
       
FirstEnergy Solutions Corp.
       
 
       
    5  
 
       
    6  
 
       
    7  
 
       
Ohio Edison Company
       
 
       
    8  
 
       
    9  
 
       
    10  
 
       
The Cleveland Electric Illuminating Company
       
 
       
    11  
 
       
    12  
 
       
    13  
 
       
The Toledo Edison Company
       
 
       
    14  
 
       
    15  
 
       
    16  
 
       
Jersey Central Power & Light Company
       
 
       
    17  
 
       
    18  
 
       
    19  
 
       
Metropolitan Edison Company
       
 
       
    20  
 
       
    21  
 
       
    22  
 
       
Pennsylvania Electric Company
       
 
       
    23  
 
       
    24  
 
       
    25  

 

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Table of Contents

TABLE OF CONTENTS (Cont’d)
         
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 Exhibit 10.1
 Exhibit 10.2
 Exhibit 10.3
 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

 

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Table of Contents

GLOSSARY OF TERMS
The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its current and former subsidiaries:
     
ATSI
 
American Transmission Systems, Incorporated, owns and operates transmission facilities
CEI
 
The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
FENOC
 
FirstEnergy Nuclear Operating Company, operates nuclear generating facilities
FES
 
FirstEnergy Solutions Corp., provides energy-related products and services
FESC
 
FirstEnergy Service Company, provides legal, financial and other corporate support services
FEV
 
FirstEnergy Ventures Corp., invests in certain unregulated enterprises and business ventures
FGCO
 
FirstEnergy Generation Corp., owns and operates non-nuclear generating facilities
FirstEnergy
 
FirstEnergy Corp., a public utility holding company
Global Rail
 
A joint venture between FirstEnergy Ventures Corp. 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, which 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
NGC
 
FirstEnergy Nuclear Generation Corp., owns nuclear generating facilities
OE
 
Ohio Edison Company, an Ohio electric utility operating subsidiary
Ohio Companies
 
CEI, OE and TE
Penelec
 
Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
Penn
 
Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
Pennsylvania Companies
 
Met-Ed, Penelec and Penn
PNBV
 
PNBV Capital Trust, a special purpose entity created by OE in 1996
Shippingport
 
Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
Signal Peak
 
A joint venture between FirstEnergy Ventures Corp. and WMB Loan Ventures LLC, that owns mining operations near Roundup, Montana
TE
 
The Toledo Edison Company, an Ohio electric utility operating subsidiary
Utilities
 
OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec
The following abbreviations and acronyms are used to identify frequently used terms in this report:
     
ALJ
  Administrative Law Judge
AOCL
 
Accumulated Other Comprehensive Loss
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
CO2
 
Carbon Dioxide
CTC
 
Competitive Transition Charge
DOE
 
United States Department of Energy
DOJ
 
United States Department of Justice
DPA
 
Department of the Public Advocate, Division of Rate Counsel (New Jersey)
EE&C
 
Energy Efficiency and Conservation
EMP
 
Energy Master Plan
EPA
 
United States Environmental Protection Agency

 

iii


Table of Contents

GLOSSARY OF TERMS, Cont’d.
     
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
GAAP
  Generally Accepted Accounting Principles in the United States
GHG
  Greenhouse Gases
IRS
  Internal Revenue Service
JOA
  Joint Operating Agreement
kV
  Kilovolt
KWH
  Kilowatt-hours
LED
  Light-Emitting Diode
LOC
  Letter of Credit
MACT
  Maximum Achievable Control Technology
MDPSC
  Maryland Public Service Commission
MEIUG
  Met-Ed Industrial users Group
MISO
  Midwest Independent Transmission System Operator, Inc.
Moody’s
  Moody’s Investors Service, Inc.
MRO
  Market Rate Offer
MTEP
  MISO Regional Transmission Expansion Plan
MW
  Megawatts
MWH
  Megawatt-hours
NAAQS
  National Ambient Air Quality Standards
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
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 whose alternative supplier fails to deliver service
PPUC
  Pennsylvania Public Utility Commission
PSCWV
  Public Service Commission of West Virginia
PSA
  Power Supply Agreement
PSD
  Prevention of Significant Deterioration
PUCO
  Public Utilities Commission of Ohio
RECs
  Renewable Energy Credits
RFP
  Request for Proposal
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


Table of Contents

GLOSSARY OF TERMS, Cont’d.
     
SEC
  U.S. Securities and Exchange Commission
SIP
  State Implementation Plan(s) Under the Clean Air Act
SNCR
  Selective Non-Catalytic Reduction
SO2
  Sulfur Dioxide
TBC
  Transition Bond Charge
TMI-2
  Three Mile Island Unit 2
TSC
  Transmission Service Charge
VIE
  Variable Interest Entity
VSCC
  Virginia State Corporation Commission

 

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Table of Contents

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
                                 
    Three Months     Nine Months  
    Ended September 30     Ended September 30  
    2010     2009     2010     2009  
    (In millions, except per share amounts)  
REVENUES:
                               
Electric utilities
  $ 2,757     $ 2,940     $ 7,673     $ 8,751  
Unregulated businesses
    936       468       2,449       1,262  
 
                       
Total revenues*
    3,693       3,408       10,122       10,013  
 
                       
 
                               
EXPENSES:
                               
Fuel
    400       302       1,084       890  
Purchased power
    1,284       1,313       3,574       3,480  
Other operating expenses
    738       665       2,112       2,103  
Provision for depreciation
    182       188       565       550  
Amortization of regulatory assets
    176       261       549       903  
Deferral of new regulatory assets
                      (136 )
General taxes
    206       192       587       587  
Impairment of long-lived assets
    292             294        
 
                       
Total expenses
    3,278       2,921       8,765       8,377  
 
                       
 
                               
OPERATING INCOME
    415       487       1,357       1,636  
 
                       
 
                               
OTHER INCOME (EXPENSE):
                               
Investment income
    46       191       93       207  
Interest expense
    (208 )     (355 )     (628 )     (755 )
Capitalized interest
    41       35       122       96  
 
                       
Total other expense
    (121 )     (129 )     (413 )     (452 )
 
                       
 
                               
INCOME BEFORE INCOME TAXES
    294       358       944       1,184  
 
                               
INCOME TAXES
    119       128       364       430  
 
                       
 
                               
NET INCOME
    175       230       580       754  
 
                               
Loss attributable to noncontrolling interest
    (4 )     (4 )     (19 )     (14 )
 
                       
 
                               
EARNINGS AVAILABLE TO FIRSTENERGY CORP.
  $ 179     $ 234     $ 599     $ 768  
 
                       
 
                               
BASIC EARNINGS PER SHARE OF COMMON STOCK
  $ 0.59     $ 0.77     $ 1.97     $ 2.52  
 
                       
 
                               
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING
    304       304       304       304  
 
                       
 
                               
DILUTED EARNINGS PER SHARE OF COMMON STOCK
  $ 0.59     $ 0.77     $ 1.96     $ 2.51  
 
                       
 
                               
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING
    305       306       305       306  
 
                       
 
                               
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK
  $ 1.10     $ 1.10     $ 1.65     $ 1.65  
 
                       
     
*  
Includes excise tax collections of $120 million and $106 million in the three months ended September 30, 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.

 

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

 

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FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                 
    September 30,     December 31,  
    2010     2009  
    (In millions)  
ASSETS
               
 
               
CURRENT ASSETS:
               
Cash and cash equivalents
  $ 632     $ 874  
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  
Prepaid taxes
    291       248  
Other
    252       154  
 
           
 
    3,391       3,320  
 
           
PROPERTY, PLANT AND EQUIPMENT:
               
In service
    27,590       27,826  
Less — Accumulated provision for depreciation
    11,206       11,397  
 
           
 
    16,384       16,429  
Construction work in progress
    3,154       2,735  
 
           
 
    19,538       19,164  
 
           
INVESTMENTS:
               
Nuclear plant decommissioning trusts
    1,965       1,859  
Investments in lease obligation bonds
    486       543  
Other
    564       621  
 
           
 
    3,015       3,023  
 
           
DEFERRED CHARGES AND OTHER ASSETS:
               
Goodwill
    5,575       5,575  
Regulatory assets
    2,246       2,356  
Power purchase contract asset
    116       200  
Other
    826       666  
 
           
 
    8,763       8,797  
 
           
 
  $ 34,707     $ 34,304  
 
           
LIABILITIES AND CAPITALIZATION
               
 
               
CURRENT LIABILITIES:
               
Currently payable long-term debt
  $ 1,590     $ 1,834  
Short-term borrowings
    1,000       1,181  
Accounts payable
    813       829  
Accrued taxes
    230       314  
Other
    1,339       1,130  
 
           
 
    4,972       5,288  
 
           
CAPITALIZATION:
               
Common stockholders’ equity-
               
Common stock, $0.10 par value, authorized 375,000,000 shares- 304,835,407 shares outstanding
    31       31  
Other paid-in capital
    5,445       5,448  
Accumulated other comprehensive loss
    (1,350 )     (1,415 )
Retained earnings
    4,591       4,495  
 
           
Total common stockholders’ equity
    8,717       8,559  
Noncontrolling interest
    (26 )     (2 )
 
           
Total equity
    8,691       8,557  
Long-term debt and other long-term obligations
    12,104       11,908  
 
           
 
    20,795       20,465  
 
           
NONCURRENT LIABILITIES:
               
Accumulated deferred income taxes
    2,824       2,468  
Retirement benefits
    1,541       1,534  
Asset retirement obligations
    1,394       1,425  
Deferred gain on sale and leaseback transaction
    968       993  
Power purchase contract liability
    756       643  
Lease market valuation liability
    228       262  
Other
    1,229       1,226  
 
           
 
    8,940       8,551  
 
           
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
               
 
  $ 34,707     $ 34,304  
 
           
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

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FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
                 
    Nine Months Ended  
    September 30  
    2010     2009  
    (In millions)  
 
               
CASH FLOWS FROM OPERATING ACTIVITIES:
               
Net Income
  $ 580     $ 754  
Adjustments to reconcile net income to net cash from operating activities-
               
Provision for depreciation
    565       550  
Amortization of regulatory assets
    549       903  
Deferral of new regulatory assets
          (136 )
Nuclear fuel and lease amortization
    123       92  
Deferred purchased power and other costs
    (192 )     (235 )
Deferred income taxes and investment tax credits, net
    259       421  
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 )
Accrued compensation and retirement benefits
    48       20  
Interest rate swap transactions
    129        
Commodity derivative transactions, net
    (40 )     26  
Cash collateral paid, net
    (54 )     (85 )
Pension trust contribution
          (500 )
Decrease (increase) in operating assets-
               
Receivables
    (172 )     78  
Materials and supplies
    (6 )     30  
Prepayments and other current assets
    (4 )     (349 )
Increase (decrease) in operating liabilities-
               
Accounts payable
    (16 )     (103 )
Accrued taxes
    (18 )     (97 )
Accrued interest
    63       121  
Other
    4       (15 )
 
           
Net cash provided from operating activities
    2,073       1,464  
 
           
 
               
CASH FLOWS FROM FINANCING ACTIVITIES:
               
New Financing-
               
Long-term debt
    251       4,151  
Redemptions and Repayments-
               
Long-term debt
    (422 )     (2,213 )
Short-term borrowings, net
    (171 )     (764 )
Common stock dividend payments
    (503 )     (503 )
Other
    (25 )     (54 )
 
           
Net cash provided from (used for) financing activities
    (870 )     617  
 
           
 
               
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Property additions
    (1,467 )     (1,575 )
Proceeds from asset sales
    117       19  
Sales of investment securities held in trusts
    2,577       3,039  
Purchases of investment securities held in trusts
    (2,610 )     (3,101 )
Customer acquisition costs
    (110 )      
Cash investments
    56       (4 )
Restricted funds for debt redemption
          (150 )
Other
    (8 )     (16 )
 
           
Net cash used for investing activities
    (1,445 )     (1,788 )
 
           
 
               
Net change in cash and cash equivalents
    (242 )     293  
Cash and cash equivalents at beginning of period
    874       545  
 
           
Cash and cash equivalents at end of period
  $ 632     $ 838  
 
           
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

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FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                                 
    Three Months Ended     Nine Months Ended  
    September 30     September 30  
    2010     2009     2010     2009  
    (In thousands)  
REVENUES:
                               
Electric sales to affiliates
  $ 599,695     $ 616,300     $ 1,745,542     $ 2,348,741  
Electric sales to non-affiliates
    904,752       443,819       2,302,240       928,944  
Other
    49,230       44,453       208,662       394,145  
 
                       
Total revenues
    1,553,677       1,104,572       4,256,444       3,671,830  
 
                       
 
                               
EXPENSES:
                               
Fuel
    391,087       294,693       1,061,719       871,160  
Purchased power from affiliates
    116,381       35,290       246,232       149,746  
Purchased power from non-affiliates
    411,084       205,200       1,160,119       551,155  
Other operating expenses
    309,793       305,935       916,366       891,555  
Provision for depreciation
    59,298       66,041       185,535       192,962  
General taxes
    21,804       21,700       70,822       66,361  
Impairment of long-lived assets
    291,934             293,767        
 
                       
Total expenses
    1,601,381       928,859       3,934,560       2,722,939  
 
                       
 
                               
OPERATING INCOME (LOSS)
    (47,704 )     175,713       321,884       948,891  
 
                       
 
                               
OTHER INCOME (EXPENSE):
                               
Investment income
    29,895       158,857       43,978       135,723  
Miscellaneous income
    4,765       2,804       10,468       12,840  
Interest expense — affiliates
    (2,497 )     (2,209 )     (7,362 )     (8,503 )
Interest expense — other
    (49,544 )     (42,187 )     (150,560 )     (90,985 )
Capitalized interest
    22,955       17,869       66,550       41,975  
 
                       
Total other income (expense)
    5,574       135,134       (36,926 )     91,050  
 
                       
 
                               
INCOME (LOSS) BEFORE INCOME TAXES
    (42,130 )     310,847       284,958       1,039,941  
 
                               
INCOME TAXES
    (5,404 )     111,164       107,833       372,175  
 
                       
 
                               
NET INCOME (LOSS)
    (36,726 )     199,683       177,125       667,766  
 
                       
 
                               
OTHER COMPREHENSIVE INCOME (LOSS):
                               
Pension and other postretirement benefits
    886       (61,085 )     (8,063 )     13,604  
Unrealized gain on derivative hedges
    2,818       790       7,109       26,847  
Change in unrealized gain on available-for-sale securities
    17,445       (89,401 )     28,533       (51,374 )
 
                       
Other comprehensive income (loss)
    21,149       (149,696 )     27,579       (10,923 )
Income taxes related to other comprehensive income (loss)
    7,694       (58,883 )     9,898       (3,549 )
 
                       
Other comprehensive income (loss), net of tax
    13,455       (90,813 )     17,681       (7,374 )
 
                       
 
                               
TOTAL COMPREHENSIVE INCOME (LOSS)
  $ (23,271 )   $ 108,870     $ 194,806     $ 660,392  
 
                       
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

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FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                 
    September 30,     December 31,  
    2010     2009  
    (In thousands)  
ASSETS
               
 
               
CURRENT ASSETS:
               
Cash and cash equivalents
  $ 10     $ 12  
Receivables-
               
Customers (less accumulated provisions of $16,277,000 and $12,041,000, respectively, for uncollectible accounts)
    325,265       195,107  
Associated companies
    269,986       318,561  
Other (less accumulated provisions of $6,702,000 for uncollectible accounts)
    57,407       51,872  
Notes receivable from associated companies
    501,648       805,103  
Materials and supplies, at average cost
    554,043       539,541  
Prepayments and other
    204,065       107,782  
 
           
 
    1,912,424       2,017,978  
 
           
PROPERTY, PLANT AND EQUIPMENT:
               
In service
    9,663,264       10,357,632  
Less — Accumulated provision for depreciation
    4,114,381       4,531,158  
 
           
 
    5,548,883       5,826,474  
Construction work in progress
    2,736,635       2,423,446  
 
           
 
    8,285,518       8,249,920  
 
           
INVESTMENTS:
               
Nuclear plant decommissioning trusts
    1,158,376       1,088,641  
Other
    7,400       22,466  
 
           
 
    1,165,776       1,111,107  
 
           
DEFERRED CHARGES AND OTHER ASSETS:
               
Accumulated deferred income tax benefits
    3,357       86,626  
Customer intangibles
    127,420       16,566  
Goodwill
    24,248       24,248  
Property taxes
    50,125       50,125  
Unamortized sale and leaseback costs
    61,934       72,553  
Other
    164,332       121,665  
 
           
 
    431,416       371,783  
 
           
 
  $ 11,795,134     $ 11,750,788  
 
           
LIABILITIES AND CAPITALIZATION
               
 
               
CURRENT LIABILITIES:
               
Currently payable long-term debt
  $ 1,396,792     $ 1,550,927  
Short-term borrowings-
               
Associated companies
    9,642       9,237  
Other
    100,000       100,000  
Accounts payable-
               
Associated companies
    472,018       466,078  
Other
    204,928       245,363  
Accrued taxes
    59,422       83,158  
Other
    430,824       359,057  
 
           
 
    2,673,626       2,813,820  
 
           
CAPITALIZATION:
               
Common stockholders’ equity-
               
Common stock, without par value, authorized 750 shares, 7 shares outstanding
    1,490,010       1,468,423  
Accumulated other comprehensive loss
    (85,320 )     (103,001 )
Retained earnings
    2,326,274       2,149,149  
 
           
Total common stockholders’ equity
    3,730,964       3,514,571  
Long-term debt and other long-term obligations
    2,819,150       2,711,652  
 
           
 
    6,550,114       6,226,223  
 
           
NONCURRENT LIABILITIES:
               
Deferred gain on sale and leaseback transaction
    967,583       992,869  
Accumulated deferred investment tax credits
    55,267       58,396  
Asset retirement obligations
    877,522       921,448  
Retirement benefits
    228,779       204,035  
Property taxes
    50,125       50,125  
Lease market valuation liability
    228,119       262,200  
Other
    163,999       221,672  
 
           
 
    2,571,394       2,710,745  
 
           
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
               
 
  $ 11,795,134     $ 11,750,788  
 
           
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

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FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
                 
    Nine Months Ended  
    September 30  
    2010     2009  
    (In thousands)  
 
               
CASH FLOWS FROM OPERATING ACTIVITIES:
               
Net Income
  $ 177,125     $ 667,766  
Adjustments to reconcile net income to net cash from operating activities-
               
Provision for depreciation
    185,535       192,962  
Nuclear fuel and lease amortization
    126,071       94,244  
Deferred rents and lease market valuation liability
    (41,493 )     (40,143 )
Deferred income taxes and investment tax credits, net
    96,152       268,812  
Impairment of long-lived assets
    293,767        
Investment impairment
    21,089       36,169  
Accrued compensation and retirement benefits
    15,887       5,860  
Commodity derivative transactions, net
    (40,048 )     25,794  
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 )
Decrease (increase) in operating assets-
               
Receivables
    (91,134 )     (55,774 )
Materials and supplies
    (15,324 )     38,543  
Prepayments and other current assets
    36,004       (35,315 )
Increase (decrease) in operating liabilities-
               
Accounts payable
    (50,114 )     (72,181 )
Accrued taxes
    (8,404 )     23,846  
Accrued interest
    (14,130 )     31,770  
Other
    23,349       (43,369 )
 
           
Net cash provided from operating activities
    623,927       881,811  
 
           
 
               
CASH FLOWS FROM FINANCING ACTIVITIES:
               
New Financing-
               
Long-term debt
    249,520       2,356,762  
Short-term borrowings, net
    405        
Redemptions and Repayments-
               
Long-term debt
    (296,339 )     (618,213 )
Short-term borrowings, net
          (1,164,823 )
Other
    (798 )     (20,006 )
 
           
Net cash provided from (used for) financing activities
    (47,212 )     553,720  
 
           
 
               
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Property additions
    (801,238 )     (842,600 )
Proceeds from asset sales
    117,213       16,129  
Sales of investment securities held in trusts
    1,478,086       2,152,717  
Purchases of investment securities held in trusts
    (1,511,273 )     (2,175,135 )
Loans from (to) associated companies, net
    303,455       (298,841 )
Customer acquisition costs
    (110,073 )      
Leasehold improvement payments to associated companies
    (51,204 )      
Other
    (1,683 )     (20,882 )
 
           
Net cash used for investing activities
    (576,717 )     (1,168,612 )
 
           
 
               
Net change in cash and cash equivalents
    (2 )     266,919  
Cash and cash equivalents at beginning of period
    12       39  
 
           
Cash and cash equivalents at end of period
  $ 10     $ 266,958  
 
           
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

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

 

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OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                 
    September 30,     December 31,  
    2010     2009  
    (In thousands)  
ASSETS
               
 
CURRENT ASSETS:
               
Cash and cash equivalents
  $ 288,092     $ 324,175  
Receivables-
               
Customers (less accumulated provisions of $4,951,000 and $5,119,000, respectively, for uncollectible accounts)
    182,894       209,384  
Associated companies
    38,499       98,874  
Other
    20,777       14,155  
Notes receivable from associated companies
    16,234       118,651  
Prepayments and other
    9,490       15,964  
 
           
 
    555,986       781,203  
 
           
UTILITY PLANT:
               
In service
    3,118,239       3,036,467  
Less — Accumulated provision for depreciation
    1,199,401       1,165,394  
 
           
 
    1,918,838       1,871,073  
Construction work in progress
    38,915       31,171  
 
           
 
    1,957,753       1,902,244  
 
           
OTHER PROPERTY AND INVESTMENTS:
               
Investment in lease obligation bonds
    204,707       216,600  
Nuclear plant decommissioning trusts
    129,685       120,812  
Other
    96,897       96,861  
 
           
 
    431,289       434,273  
 
           
DEFERRED CHARGES AND OTHER ASSETS:
               
Regulatory assets
    413,596       465,331  
Pension assets
    39,271       19,881  
Property taxes
    67,037       67,037  
Unamortized sale and leaseback costs
    31,376       35,127  
Other
    17,540       39,881  
 
           
 
    568,820       627,257  
 
           
 
  $ 3,513,848     $ 3,744,977  
 
           
LIABILITIES AND CAPITALIZATION
               
 
CURRENT LIABILITIES:
               
Currently payable long-term debt
  $ 1,479     $ 2,723  
Short-term borrowings-
               
Associated companies
    47,648       92,863  
Other
    320       807  
Accounts payable-
               
Associated companies
    32,084       102,763  
Other
    23,994       40,423  
Accrued taxes
    55,236       81,868  
Accrued interest
    25,354       25,749  
Other
    133,060       81,424  
 
           
 
    319,175       428,620  
 
           
CAPITALIZATION:
               
Common stockholder’s equity-
               
Common stock, without par value, authorized 175,000,000 shares - 60 shares outstanding
    951,839       1,154,797  
Accumulated other comprehensive loss
    (157,159 )     (163,577 )
Retained earnings
    104,241       29,890  
 
           
Total common stockholder’s equity
    898,921       1,021,110  
Noncontrolling interest
    6,225       6,442  
 
           
Total equity
    905,146       1,027,552  
Long-term debt and other long-term obligations
    1,152,370       1,160,208  
 
           
 
    2,057,516       2,187,760  
 
           
NONCURRENT LIABILITIES:
               
Accumulated deferred income taxes
    678,815       660,114  
Accumulated deferred investment tax credits
    10,521       11,406  
Retirement benefits
    169,070       174,925  
Asset retirement obligations
    83,194       85,926  
Other
    195,557       196,226  
 
           
 
    1,137,157       1,128,597  
 
           
COMMITMENTS AND CONTINGENCIES (Note 9)
               
 
  $ 3,513,848     $ 3,744,977  
 
           
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

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OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
                 
    Nine Months Ended  
    September 30  
    2010     2009  
    (In thousands)  
 
               
CASH FLOWS FROM OPERATING ACTIVITIES:
               
Net Income
  $ 119,737     $ 80,011  
Adjustments to reconcile net income to net cash from operating activities-
               
Provision for depreciation
    65,884       65,916  
Amortization of regulatory assets, net
    48,473       59,910  
Purchased power cost recovery reconciliation
    3,906       15,372  
Amortization of lease costs
    28,314       28,394  
Deferred income taxes and investment tax credits, net
    7,612       32,658  
Accrued compensation and retirement benefits
    (16,659 )     (3,542 )
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 )
Decrease (increase) in operating assets-
               
Receivables
    91,971       128,688  
Prepayments and other current assets
    10,331       (2,553 )
Decrease in operating liabilities-
               
Accounts payable
    (87,108 )     (60,125 )
Accrued taxes
    (26,425 )     (17,196 )
Accrued interest
    (395 )     (59 )
Other
    (9,695 )     (8,596 )
 
           
Net cash provided from operating activities
    260,533       236,850  
 
           
 
               
CASH FLOWS FROM FINANCING ACTIVITIES:
               
New Financing-
               
Long-term debt
          100,000  
Short-term borrowings, net
          74,514  
Redemptions and Repayments-
               
Long-term debt
    (9,628 )     (101,088 )
Short-term borrowings, net
    (45,702 )      
Common stock dividend payments
    (250,000 )     (150,000 )
Other
    (892 )     (2,138 )
 
           
Net cash used for financing activities
    (306,222 )     (78,712 )
 
           
 
               
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Property additions
    (110,645 )     (108,253 )
Leasehold improvement payments from associated companies
    18,375        
Sales of investment securities held in trusts
    78,599       207,280  
Purchases of investment securities held in trusts
    (83,725 )     (214,592 )
Loan repayments from associated companies, net
    102,417       134,975  
Cash investments
    12,296       7,070  
Other
    (7,711 )     (1,216 )
 
           
Net cash provided from investing activities
    9,606       25,264  
 
           
 
               
Net change in cash and cash equivalents
    (36,083 )     183,402  
Cash and cash equivalents at beginning of period
    324,175       146,343  
 
           
Cash and cash equivalents at end of period
  $ 288,092     $ 329,745  
 
           
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

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THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                                 
    Three Months Ended     Nine Months Ended  
    September 30     September 30  
    2010     2009     2010     2009  
    (In thousands)  
STATEMENTS OF INCOME
                               
 
                               
REVENUES:
                               
Electric sales
  $ 309,236     $ 417,900     $ 901,913     $ 1,307,592  
Excise tax collections
    19,480       17,629       52,548       52,748  
 
                       
Total revenues
    328,716       435,529       954,461       1,360,340  
 
                       
 
                               
EXPENSES:
                               
Purchased power from affiliates
    89,389       153,556       298,204       635,927  
Purchased power from non-affiliates
    35,151       87,689       105,200       208,849  
Other operating expenses
    36,441       37,822       96,613       141,829  
Provision for depreciation
    18,057       17,753       54,504       53,885  
Amortization of regulatory assets
    45,136       39,313       121,082       325,630  
Deferral of new regulatory assets
                      (134,587 )
General taxes
    39,878       37,752       107,207       112,749  
 
                       
Total expenses
    264,052       373,885       782,810       1,344,282  
 
                       
 
                               
OPERATING INCOME
    64,664       61,644       171,651       16,058  
 
                       
 
                               
OTHER INCOME (EXPENSE):
                               
Investment income
    6,604       7,565       20,756       23,599  
Miscellaneous income
    533       645       1,790       3,437  
Interest expense
    (33,384 )     (34,740 )     (100,267 )     (100,819 )
Capitalized interest
    10       27       43       145  
 
                       
Total other expense
    (26,237 )     (26,503 )     (77,678 )     (73,638 )
 
                       
 
                               
INCOME (LOSS) BEFORE INCOME TAXES
    38,427       35,141       93,973       (57,580 )
 
                               
INCOME TAX EXPENSE (BENEFIT)
    13,479       9,755       33,107       (25,290 )
 
                       
 
                               
NET INCOME (LOSS)
    24,948       25,386       60,866       (32,290 )
 
                       
 
                               
Income from noncontrolling interest
    366       418       1,151       1,295  
 
                       
 
                               
EARNINGS (LOSS) AVAILABLE TO PARENT
  $ 24,582     $ 24,968     $ 59,715     $ (33,585 )
 
                       
 
                               
STATEMENTS OF COMPREHENSIVE INCOME
                               
 
                               
NET INCOME (LOSS)
  $ 24,948     $ 25,386     $ 60,866     $ (32,290 )
 
                       
 
                               
OTHER COMPREHENSIVE INCOME (LOSS):
                               
Pension and other postretirement benefits
    3,228       (48,024 )     (16,129 )     (154 )
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  
 
                       
Other comprehensive income (loss), net of tax
    2,252       (31,621 )     (9,804 )     (3,057 )
 
                       
 
                               
COMPREHENSIVE INCOME (LOSS)
    27,200       (6,235 )     51,062       (35,347 )
 
                               
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST
    366       418       1,151       1,295  
 
                       
 
                               
COMPREHENSIVE INCOME (LOSS) AVAILABLE TO PARENT
  $ 26,834     $ (6,653 )   $ 49,911     $ (36,642 )
 
                       
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

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THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                 
    September 30,     December 31,  
    2010     2009  
    (In thousands)  
ASSETS
               
 
               
CURRENT ASSETS:
               
Cash and cash equivalents
  $ 247     $ 86,230  
Receivables-
               
Customers (less accumulated provisions of $5,271,000 and $5,239,000, respectively, for uncollectible accounts)
    186,044       209,335  
Associated companies
    59,339       98,954  
Other
    4,910       11,661  
Notes receivable from associated companies
    23,905       26,802  
Prepayments and other
    4,362       9,973  
 
           
 
    278,807       442,955  
 
           
UTILITY PLANT:
               
In service
    2,373,419       2,310,074  
Less — Accumulated provision for depreciation
    921,040       888,169  
 
           
 
    1,452,379       1,421,905  
Construction work in progress
    30,482       36,907  
 
           
 
    1,482,861       1,458,812  
 
           
OTHER PROPERTY AND INVESTMENTS:
               
Investment in lessor notes
    340,031       388,641  
Other
    10,084       10,220  
 
           
 
    350,115       398,861  
 
           
DEFERRED CHARGES AND OTHER ASSETS:
               
Goodwill
    1,688,521       1,688,521  
Regulatory assets
    420,144       545,505  
Pension assets (Note 6)
          13,380  
Property taxes
    77,319       77,319  
Other
    12,897       12,777  
 
           
 
    2,198,881       2,337,502  
 
           
 
  $ 4,310,664     $ 4,638,130  
 
           
LIABILITIES AND CAPITALIZATION
               
 
               
CURRENT LIABILITIES:
               
Currently payable long-term debt
  $ 148     $ 117  
Short-term borrowings-
               
Associated companies
    129,912       339,728  
Accounts payable-
               
Associated companies
    14,803       68,634  
Other
    13,725       17,166  
Accrued taxes
    64,492       90,511  
Accrued interest
    39,261       18,466  
Other
    63,732       45,440  
 
           
 
    326,073       580,062  
 
           
CAPITALIZATION:
               
Common stockholders’ equity-
               
Common stock, without par value, authorized 105,000,000 shares, 67,930,743 shares outstanding
    886,927       884,897  
Accumulated other comprehensive loss
    (147,962 )     (138,158 )
Retained earnings
    556,963       597,248  
 
           
Total common stockholders’ equity
    1,295,928       1,343,987  
Noncontrolling interest
    17,651       20,592  
 
           
Total equity
    1,313,579       1,364,579  
Long-term debt and other long-term obligations
    1,852,511       1,872,750  
 
           
 
    3,166,090       3,237,329  
 
           
NONCURRENT LIABILITIES:
               
Accumulated deferred income taxes
    628,244       644,745  
Accumulated deferred investment tax credits
    11,205       11,836  
Retirement benefits
    82,070       69,733  
Other
    96,982       94,425  
 
           
 
    818,501       820,739  
 
           
COMMITMENTS AND CONTINGENCIES (Note 9)
               
 
  $ 4,310,664     $ 4,638,130  
 
           
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

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THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
                 
    Nine Months Ended  
    September 30  
    2010     2009  
    (In thousands)  
 
               
CASH FLOWS FROM OPERATING ACTIVITIES:
               
Net Income (Loss)
  $ 60,866     $ (32,290 )
Adjustments to reconcile net income (loss) to net cash from operating activities-
               
Provision for depreciation
    54,504       53,885  
Amortization of regulatory assets, net
    121,082       325,630  
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 )
Accrued compensation and retirement benefits
    10,467       10,311  
Pension trust contribution
          (89,789 )
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  
Prepayments and other current assets
    5,421       (633 )
Increase (decrease) in operating liabilities-
               
Accounts payable
    (57,272 )     (32,240 )
Accrued taxes
    (23,876 )     (17,003 )
Accrued interest
    20,795       29,816  
Other
    740       11,489  
 
           
Net cash provided from operating activities
    274,414       112,043  
 
           
 
               
CASH FLOWS FROM FINANCING ACTIVITIES:
               
New Financing-
               
Long-term debt
          298,398  
Redemptions and Repayments-
               
Long-term debt
    (84 )     (558 )
Short-term borrowings, net
    (230,132 )     (111,128 )
Common stock dividend payments
    (100,000 )     (93,000 )
Other
    (4,100 )     (6,161 )
 
           
Net cash provided from (used for) financing activities
    (334,316 )     87,551  
 
           
 
               
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Property additions
    (70,812 )     (73,577 )
Restricted cash
          (155,573 )
Loan repayments from (to) associated companies, net
    2,897       (4,638 )
Redemptions of lessor notes
    48,610       37,072  
Other
    (6,776 )     (2,871 )
 
           
Net cash used for investing activities
    (26,081 )     (199,587 )
 
           
 
               
Net change in cash and cash equivalents
    (85,983 )     7  
Cash and cash equivalents at beginning of period
    86,230       226  
 
           
Cash and cash equivalents at end of period
  $ 247     $ 233  
 
           
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

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THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                                 
    Three Months Ended     Nine Months Ended  
    September 30     September 30  
    2010     2009     2010     2009  
    (In thousands)  
STATEMENTS OF INCOME
                               
 
                               
REVENUES:
                               
Electric sales
  $ 136,058     $ 206,086     $ 376,180     $ 663,082  
Excise tax collections
    7,979       7,422       21,079       21,448  
 
                       
Total revenues
    144,037       213,508       397,259       684,530  
 
                       
 
                               
EXPENSES:
                               
Purchased power from affiliates
    42,338       86,278       144,062       342,166  
Purchased power from non-affiliates
    16,663       56,494       50,377       115,275  
Other operating expenses
    28,746       30,238       79,790       110,722  
Provision for depreciation
    7,800       7,847       23,763       23,136  
Amortization (deferral) of regulatory assets, net
    6,591       9,253       (3,708 )     30,921  
General taxes
    14,023       13,205       39,766       39,804  
 
                       
Total expenses
    116,161       203,315       334,050       662,024  
 
                       
 
                               
OPERATING INCOME
    27,876       10,193       63,209       22,506  
 
                       
 
                               
OTHER INCOME (EXPENSE):
                               
Investment income
    3,018       9,302       11,875       22,315  
Miscellaneous expense
    (502 )     (1,725 )     (2,853 )     (1,690 )
Interest expense
    (10,479 )     (10,854 )     (31,421 )     (25,649 )
Capitalized interest
    94       46       252       138  
 
                       
Total other expense
    (7,869 )     (3,231 )     (22,147 )     (4,886 )
 
                       
 
                               
INCOME BEFORE INCOME TAXES
    20,007       6,962       41,062       17,620  
 
                               
INCOME TAX EXPENSE (BENEFIT)
    6,911       (138 )     13,241       3,123  
 
                       
 
                               
NET INCOME
    13,096       7,100       27,821       14,497  
 
                       
 
                               
Income from noncontrolling interest
    (4 )     14       1       17  
 
                       
 
                               
EARNINGS AVAILABLE TO PARENT
  $ 13,100     $ 7,086     $ 27,820     $ 14,480  
 
                       
 
                               
STATEMENTS OF COMPREHENSIVE INCOME
                               
 
                               
NET INCOME
  $ 13,096     $ 7,100     $ 27,821     $ 14,497  
 
                       
 
                               
OTHER COMPREHENSIVE INCOME (LOSS):
                               
Pension and other postretirement benefits
    713       (24,201 )     1,723       (5,052 )
Change in unrealized gain on available-for-sale securities
    427       (11,633 )     466       (15,181 )
 
                       
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 (loss), net of tax
    810       (22,647 )     1,624       (14,251 )
 
                       
 
                               
COMPREHENSIVE INCOME (LOSS)
    13,906       (15,547 )     29,445       246  
 
                               
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTEREST
    (4 )     14       1       17  
 
                       
 
                               
COMPREHENSIVE INCOME (LOSS) AVAILABLE TO PARENT
  $ 13,910     $ (15,561 )   $ 29,444     $ 229  
 
                       
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

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THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                 
    September 30,     December 31,  
    2010     2009  
    (In thousands)  
ASSETS
               
 
               
CURRENT ASSETS:
               
Cash and cash equivalents
  $ 134,158     $ 436,712  
Receivables-
               
Customers
    30       75  
Associated companies
    44,075       90,191  
Other (less accumulated provisions of $224,000 and $208,000, respectively, for uncollectible accounts)
    19,146       20,180  
Notes receivable from associated companies
    81,254       85,101  
Prepayments and other
    4,272       7,111  
 
           
 
    282,935       639,370  
 
           
UTILITY PLANT:
               
In service
    938,532       912,930  
Less — Accumulated provision for depreciation
    440,510       427,376  
 
           
 
    498,022       485,554  
Construction work in progress
    9,946       9,069  
 
           
 
    507,968       494,623  
 
           
OTHER PROPERTY AND INVESTMENTS:
               
Investment in lessor notes
    103,848       124,357  
Nuclear plant decommissioning trusts
    76,051       73,935  
Other
    1,514       1,580  
 
           
 
    181,413       199,872  
 
           
DEFERRED CHARGES AND OTHER ASSETS:
               
Goodwill
    500,576       500,576  
Regulatory assets
    74,297       69,557  
Property taxes
    23,658       23,658  
Other
    27,215       55,622  
 
           
 
    625,746       649,413  
 
           
 
  $ 1,598,062     $ 1,983,278  
 
           
LIABILITIES AND CAPITALIZATION
               
 
               
CURRENT LIABILITIES:
               
Currently payable long-term debt
  $ 208     $ 222  
Accounts payable-
               
Associated companies
    8,644       78,341  
Other
    6,212       8,312  
Notes payable to associated companies
          225,975  
Accrued taxes
    17,904       25,734  
Lease market valuation liability
    36,900       36,900  
Other
    44,745       29,273  
 
           
 
    114,613       404,757  
 
           
CAPITALIZATION:
               
Common stockholders’ equity-
               
Common stock, $5 par value, authorized 60,000,000 shares, 29,402,054 shares outstanding
    147,010       147,010  
Other paid-in-capital
    178,170       178,181  
Accumulated other comprehensive loss
    (48,179 )     (49,803 )
Retained earnings
    112,310       214,490  
 
           
Total common stockholders’ equity
    389,311       489,878  
Noncontrolling interest
    2,587       2,696  
 
           
Total equity
    391,898       492,574  
Long-term debt and other long-term obligations
    600,478       600,443  
 
           
 
    992,376       1,093,017  
 
           
NONCURRENT LIABILITIES:
               
Accumulated deferred income taxes
    116,090       80,508  
Accumulated deferred investment tax credits
    6,039       6,367  
Retirement benefits
    67,953       65,988  
Asset retirement obligations
    28,287       32,290  
Lease market valuation liability
    208,525       236,200  
Other
    64,179       64,151  
 
           
 
    491,073       485,504  
 
           
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
               
 
  $ 1,598,062     $ 1,983,278  
 
           
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

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

 

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JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                                 
    Three Months Ended     Nine Months Ended  
    September 30     September 30  
    2010     2009     2010     2009  
    (In thousands)  
REVENUES:
                               
Electric sales
  $ 952,420     $ 854,108     $ 2,353,418     $ 2,312,089  
Excise tax collections
    16,080       14,128       39,444       37,890  
 
                       
Total revenues
    968,500       868,236       2,392,862       2,349,979  
 
                       
 
                               
EXPENSES:
                               
Purchased power
    556,618       509,035       1,381,104       1,414,226  
Other operating expenses
    89,167       84,495       260,004       241,241  
Provision for depreciation
    26,614       26,565       81,678       76,969  
Amortization of regulatory assets, net
    100,476       96,051       251,250       262,900  
General taxes
    19,974       18,344       51,312       48,427  
 
                       
Total expenses
    792,849       734,490       2,025,348       2,043,763  
 
                       
 
                               
OPERATING INCOME
    175,651       133,746       367,514       306,216  
 
                       
 
                               
OTHER INCOME (EXPENSE):
                               
Miscellaneous income
    1,662       1,301       5,144       4,113  
Interest expense
    (30,220 )     (29,593 )     (89,684 )     (87,132 )
Capitalized interest
    199       139       488       419  
 
                       
Total other expense
    (28,359 )     (28,153 )     (84,052 )     (82,600 )
 
                       
 
                               
INCOME BEFORE INCOME TAXES
    147,292       105,593       283,462       223,616  
 
                               
INCOME TAXES
    64,440       43,435       121,491       95,834  
 
                       
 
                               
NET INCOME
    82,852       62,158       161,971       127,782  
 
                       
 
                               
OTHER COMPREHENSIVE INCOME (LOSS):
                               
Pension and other postretirement benefits
    4,135       (51,932 )     24,198       (26,893 )
Unrealized gain on derivative hedges
    69       69       207       207  
 
                       
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 (loss), net of tax
    2,761       (30,568 )     14,963       (17,880 )
 
                       
 
                               
TOTAL COMPREHENSIVE INCOME
  $ 85,613     $ 31,590     $ 176,934     $ 109,902  
 
                       
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

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JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                 
    September 30,     December 31,  
    2010     2009  
    (In thousands)  
ASSETS
               
 
               
CURRENT ASSETS:
               
Cash and cash equivalents
  $ 1     $ 27  
Receivables-
               
Customers (less accumulated provisions of $4,736,000 and $3,506,000, respectively, for uncollectible accounts)
    378,822       300,991  
Associated companies
    3,900       12,884  
Other
    26,024       21,877  
Notes receivable — associated companies
    64,168       102,932  
Prepaid taxes
    71,153       34,930  
Other
    15,674       12,945  
 
           
 
    559,742       486,586  
 
           
UTILITY PLANT:
               
In service
    4,568,640       4,463,490  
Less — Accumulated provision for depreciation
    1,666,918       1,617,639  
 
           
 
    2,901,722       2,845,851  
Construction work in progress
    51,857       54,251  
 
           
 
    2,953,579       2,900,102  
 
           
OTHER PROPERTY AND INVESTMENTS:
               
Nuclear plant decommissioning trusts
    175,254       166,768  
Nuclear fuel disposal trust
    208,870       199,677  
Other
    2,136       2,149  
 
           
 
    386,260       368,594  
 
           
DEFERRED CHARGES AND OTHER ASSETS:
               
Goodwill
    1,810,936       1,810,936  
Regulatory assets
    722,086       888,143  
Other
    30,608       27,096  
 
           
 
    2,563,630       2,726,175  
 
           
 
  $ 6,463,211     $ 6,481,457  
 
           
LIABILITIES AND CAPITALIZATION
               
 
               
CURRENT LIABILITIES:
               
Currently payable long-term debt
  $ 31,947     $ 30,639  
Accounts payable-
               
Associated companies
    12,743       26,882  
Other
    154,872       168,093  
Accrued taxes
    24,798       12,594  
Accrued interest
    30,003       18,256  
Other
    78,903       111,156  
 
           
 
    333,266       367,620  
 
           
CAPITALIZATION:
               
Common stockholders’ equity-
               
Common stock, $10 par value, authorized 16,000,000 shares, 13,628,447 shares outstanding
    136,284       136,284  
Other paid-in capital
    2,508,852       2,507,049  
Accumulated other comprehensive loss
    (228,049 )     (243,012 )
Retained earnings
    197,046       200,075  
 
           
Total common stockholders’ equity
    2,614,133       2,600,396  
Long-term debt and other long-term obligations
    1,779,081       1,801,589  
 
           
 
    4,393,214       4,401,985  
 
           
NONCURRENT LIABILITIES:
               
Accumulated deferred income taxes
    720,825       687,545  
Nuclear fuel disposal costs
    196,703       196,511  
Retirement benefits
    133,579       150,603  
Asset retirement obligations
    106,573       101,568  
Power purchase contract liability
    386,273       399,105  
Other
    192,778       176,520  
 
           
 
    1,736,731       1,711,852  
 
           
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
               
 
  $ 6,463,211     $ 6,481,457  
 
           
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

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JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
                 
    Nine Months Ended  
    September 30  
    2010     2009  
    (In thousands)  
 
               
CASH FLOWS FROM OPERATING ACTIVITIES:
               
Net Income
  $ 161,971     $ 127,782  
Adjustments to reconcile net income to net cash from operating activities-
               
Provision for depreciation
    81,678       76,969  
Amortization of regulatory assets, net
    251,250       262,900  
Deferred purchased power and other costs
    (85,136 )     (106,340 )
Deferred income taxes and investment tax credits, net
    14,984       40,989  
Accrued compensation and retirement benefits
    11,621       7,308  
Cash collateral paid, net
    (23,400 )     (210 )
Pension trust contribution
          (100,000 )
Decrease (increase) in operating assets-
               
Receivables
    (72,994 )     18,984  
Prepayments and other current assets
    (36,573 )     (83,538 )
Increase (decrease) in operating liabilities-
               
Accounts payable
    (37,668 )     (40,670 )
Accrued taxes
    35,326       (13,399 )
Accrued interest
    11,747       20,946  
Tax collections payable
          (9,714 )
Other
    (13,953 )     12,606  
 
           
Net cash provided from operating activities
    298,853       214,613  
 
           
 
               
CASH FLOWS FROM FINANCING ACTIVITIES:
               
New Financing-
               
Long-term debt
          299,619  
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 )
Other
    (2 )     (2,275 )
 
           
Net cash used for financing activities
    (186,705 )     (75,992 )
 
           
 
               
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Property additions
    (130,008 )     (121,342 )
Loans from (to) associated companies, net
    38,764       (660 )
Sales of investment securities held in trusts
    340,368       338,684  
Purchases of investment securities held in trusts
    (353,028 )     (351,216 )
Other
    (8,270 )     (4,152 )
 
           
Net cash used for investing activities
    (112,174 )     (138,686 )
 
           
 
               
Net change in cash and cash equivalents
    (26 )     (65 )
Cash and cash equivalents at beginning of period
    27       66  
 
           
Cash and cash equivalents at end of period
  $ 1     $ 1  
 
           
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

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METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                                 
    Three Months Ended     Nine Months Ended  
    September 30     September 30  
    2010     2009     2010     2009  
    (In thousands)  
REVENUES:
                               
Electric sales
  $ 460,864     $ 424,901     $ 1,334,454     $ 1,194,609  
Gross receipts tax collections
    23,049       20,612       65,245       58,181  
 
                       
Total revenues
    483,913       445,513       1,399,699       1,252,790  
 
                       
 
                               
EXPENSES:
                               
Purchased power from affiliates
    166,039       94,768       476,119       273,497  
Purchased power from non-affiliates
    87,561       142,495       264,765       389,705  
Other operating expenses
    141,761       63,654       333,895       221,320  
Provision for depreciation
    12,978       13,262       39,176       38,320  
Amortization of regulatory assets, net
    15,480       84,631       112,869       173,770  
General taxes
    25,029       22,540       66,663       66,509  
 
                       
Total expenses
    448,848       421,350       1,293,487       1,163,121  
 
                       
 
                               
OPERATING INCOME
    35,065       24,163       106,212       89,669  
 
                       
 
                               
OTHER INCOME (EXPENSE):
                               
Interest income
    581       2,169       2,678       8,124  
Miscellaneous income
    1,539       1,068       5,093       2,982  
Interest expense
    (13,037 )     (14,380 )     (39,812 )     (42,502 )
Capitalized interest
    176       47       461       124  
 
                       
Total other expense
    (10,741 )     (11,096 )     (31,580 )     (31,272 )
 
                       
 
                               
INCOME BEFORE INCOME TAXES
    24,324       13,067       74,632       58,397  
 
                               
INCOME TAXES
    10,084       2,324       30,968       21,027  
 
                       
 
                               
NET INCOME
    14,240       10,743       43,664       37,370  
 
                       
 
                               
OTHER COMPREHENSIVE INCOME (LOSS):
                               
Pension and other postretirement benefits
    2,161       (31,365 )     14,032       557  
Unrealized gain on derivative hedges
    84       84       252       252  
 
                       
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 (loss), net of tax
    1,522       (18,169 )     8,660       (1,464 )
 
                       
 
                               
TOTAL COMPREHENSIVE INCOME (LOSS)
  $ 15,762     $ (7,426 )   $ 52,324     $ 35,906  
 
                       
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

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METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                 
    September 30,     December 31,  
    2010     2009  
    (In thousands)  
ASSETS
               
 
               
CURRENT ASSETS:
               
Cash and cash equivalents
  $ 124     $ 120  
Receivables-
               
Customers (less accumulated provisions of $4,344,000 and $4,044,000, respectively, for uncollectible accounts)
    182,509       171,052  
Associated companies
    41,689       29,413  
Other
    13,654       11,650  
Notes receivable from associated companies
    11,201       97,150  
Prepaid taxes
    27,307       15,229  
Other
    2,523       1,459  
 
           
 
    279,007       326,073  
 
           
UTILITY PLANT:
               
In service
    2,213,765       2,162,815  
Less — Accumulated provision for depreciation
    836,821       810,746  
 
           
 
    1,376,944       1,352,069  
Construction work in progress
    31,488       14,901  
 
           
 
    1,408,432       1,366,970  
 
           
OTHER PROPERTY AND INVESTMENTS:
               
Nuclear plant decommissioning trusts
    277,823       266,479  
Other
    877       890  
 
           
 
    278,700       267,369  
 
           
DEFERRED CHARGES AND OTHER ASSETS:
               
Goodwill
    416,499       416,499  
Regulatory assets
    400,375       356,754  
Power purchase contract asset
    103,902       176,111  
Other
    64,084       36,544  
 
           
 
    984,860       985,908  
 
           
 
  $ 2,950,999     $ 2,946,320  
 
           
LIABILITIES AND CAPITALIZATION
               
 
               
CURRENT LIABILITIES:
               
Currently payable long-term debt
  $ 28,500     $ 128,500  
Short-term borrowings-
               
Associated companies
    6,296        
Accounts payable-
               
Associated companies
    34,204       40,521  
Other
    28,604       41,050  
Accrued taxes
    2,967       11,170  
Accrued interest
    11,717       17,362  
Other
    31,993       24,520  
 
           
 
    144,281       263,123  
 
           
CAPITALIZATION:
               
Common stockholders’ equity-
               
Common stock, without par value, authorized 900,000 shares, 859,500 shares outstanding
    1,197,064       1,197,070  
Accumulated other comprehensive loss
    (134,891 )     (143,551 )
Retained earnings
    48,064       4,399  
 
           
Total common stockholders’ equity
    1,110,237       1,057,918  
Long-term debt and other long-term obligations
    713,941       713,873  
 
           
 
    1,824,178       1,771,791  
 
           
NONCURRENT LIABILITIES:
               
Accumulated deferred income taxes
    489,608       453,462  
Accumulated deferred investment tax credits
    6,978       7,313  
Nuclear fuel disposal costs
    44,434       44,391  
Retirement benefits
    28,268       33,605  
Asset retirement obligations
    189,489       180,297  
Power purchase contract liability
    175,259       143,135  
Other
    48,504       49,203  
 
           
 
    982,540       911,406  
 
           
COMMITMENTS AND CONTINGENCIES (Note 9)
               
 
  $ 2,950,999     $ 2,946,320  
 
           
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

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METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
                 
    Nine Months Ended  
    September 30  
    2010     2009  
    (In thousands)  
 
               
CASH FLOWS FROM OPERATING ACTIVITIES:
               
Net Income
  $ 43,664     $ 37,370  
Adjustments to reconcile net income to net cash from operating activities-
               
Provision for depreciation
    39,176       38,320  
Amortization of regulatory assets, net
    112,869       173,770  
Deferred costs recoverable as regulatory assets
    (49,646 )     (70,044 )
Deferred income taxes and investment tax credits, net
    23,781       59,393  
Accrued compensation and retirement benefits
    (282 )     6,712  
Pension trust contribution
          (123,521 )
Cash collateral paid, net
    (17,647 )     (6,800 )
Decrease (increase) in operating assets-
               
Receivables
    (18,444 )     (23,370 )
Prepayments and other current assets
    (13,144 )     (22,614 )
Increase (decrease) in operating liabilities-
               
Accounts payable
    (18,763 )     (17,293 )
Accrued taxes
    (8,203 )     (11,095 )
Accrued interest
    (5,645 )     5,001  
Other
    7,721       11,891  
 
           
Net cash provided from operating activities
    95,437       57,720  
 
           
 
               
CASH FLOWS FROM FINANCING ACTIVITIES:
               
New Financing-
               
Long-term debt
          300,000  
Short-term borrowings, net
    6,296        
Redemptions and Repayments-
               
Long-term debt
    (100,000 )      
Short-term borrowings, net
          (265,003 )
Other
          (2,268 )
 
           
Net cash provided from (used for) financing activities
    (93,704 )     32,729  
 
           
 
               
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Property additions
    (77,921 )     (73,106 )
Sales of investment securities held in trusts
    420,116       88,802  
Purchases of investment securities held in trusts
    (427,150 )     (95,982 )
Loans from (to) associated companies, net
    85,949       (6,586 )
Other
    (2,723 )     (3,597 )
 
           
Net cash used for investing activities
    (1,729 )     (90,469 )
 
           
 
               
Net change in cash and cash equivalents
    4       (20 )
Cash and cash equivalents at beginning of period
    120       144  
 
           
Cash and cash equivalents at end of period
  $ 124     $ 124  
 
           
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

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PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                                 
    Three Months Ended     Nine Months Ended  
    September 30     September 30  
    2010     2009     2010     2009  
    (In thousands)  
REVENUES:
                               
Electric sales
  $ 372,480     $ 340,246     $ 1,108,751     $ 1,028,420  
Gross receipts tax collections
    17,414       15,246       51,100       47,342  
 
                       
Total revenues
    389,894       355,492       1,159,851       1,075,762  
 
                       
 
                               
EXPENSES:
                               
Purchased power from affiliates
    165,125       81,191       486,470       249,438  
Purchased power from non-affiliates
    92,648       144,777       270,900       397,260  
Other operating expenses
    58,832       47,785       198,296       171,375  
Provision for depreciation
    14,859       15,038       46,146       45,074  
Amortization (deferral) of regulatory assets, net
    (1,771 )     17,201       (22,259 )     44,090  
General taxes
    19,194       17,230       54,375       56,074  
 
                       
Total expenses
    348,887       323,222       1,033,928       963,311  
 
                       
 
                               
OPERATING INCOME
    41,007       32,270       125,923       112,451  
 
                       
 
                               
OTHER INCOME (EXPENSE):
                               
Miscellaneous income
    1,508       1,156       4,431       2,865  
Interest expense
    (17,581 )     (11,614 )     (52,501 )     (36,690 )
Capitalized interest
    193       23       516       74  
 
                       
Total other expense
    (15,880 )     (10,435 )     (47,554 )     (33,751 )
 
                       
 
                               
INCOME BEFORE INCOME TAXES
    25,127       21,835       78,369       78,700  
 
                               
INCOME TAXES
    5,311       6,039       28,280       29,393  
 
                       
 
                               
NET INCOME
    19,816       15,796       50,089       49,307  
 
                       
 
                               
OTHER COMPREHENSIVE INCOME (LOSS):
                               
Pension and other postretirement benefits
    1,830       (79,579 )     12,207       (47,224 )
Unrealized gain on derivative hedges
    16       17       48       49  
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 (loss), net of tax
    1,362       (46,402 )     8,004       (30,186 )
 
                       
 
                               
TOTAL COMPREHENSIVE INCOME (LOSS)
  $ 21,178     $ (30,606 )   $ 58,093     $ 19,121  
 
                       
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

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PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                 
    September 30,     December 31,  
    2010     2009  
    (In thousands)  
ASSETS
               
 
               
CURRENT ASSETS:
               
Cash and cash equivalents
  $ 8     $ 14  
Receivables-
               
Customers (less accumulated provisions of $3,481,000 and $3,483,000, respectively, for uncollectible accounts)
    135,416       139,302  
Associated companies
    95,355       77,338  
Other
    14,413       18,320  
Notes receivable from associated companies
    14,569       14,589  
Prepaid taxes
    48,264       18,946  
Other
    2,115       1,400  
 
           
 
    310,140       269,909  
 
           
UTILITY PLANT:
               
In service
    2,503,555       2,431,737  
Less — Accumulated provision for depreciation
    925,894       901,990  
 
           
 
    1,577,661       1,529,747  
Construction work in progress
    28,498       24,205  
 
           
 
    1,606,159       1,553,952  
 
           
OTHER PROPERTY AND INVESTMENTS:
               
Nuclear plant decommissioning trusts
    147,675       142,603  
Non-utility generation trusts
    92,034       120,070  
Other
    294       289  
 
           
 
    240,003       262,962  
 
           
DEFERRED CHARGES AND OTHER ASSETS:
               
Goodwill
    768,628       768,628  
Regulatory assets
    202,801       9,045  
Power purchase contract asset
    5,746       15,362  
Other
    28,780       19,143  
 
           
 
    1,005,955       812,178  
 
           
 
  $ 3,162,257     $ 2,899,001  
 
           
LIABILITIES AND CAPITALIZATION
               
 
               
CURRENT LIABILITIES:
               
Currently payable long-term debt
  $ 69,310     $ 69,310  
Short-term borrowings-
               
Associated companies
    43,244       41,473  
Accounts payable-
               
Associated companies
    40,747       39,884  
Other
    28,427       41,990  
Accrued taxes
    4,164       6,409  
Accrued interest
    24,513       17,598  
Other
    25,871       22,741  
 
           
 
    236,276       239,405  
 
           
CAPITALIZATION:
               
Common stockholders’ equity-
               
Common stock, $20 par value, authorized 5,400,000 shares, 4,427,577 shares outstanding
    88,552       88,552  
Other paid-in capital
    913,507       913,437  
Accumulated other comprehensive loss
    (154,100 )     (162,104 )
Retained earnings
    141,590       91,501  
 
           
Total common stockholders’ equity
    989,549       931,386  
Long-term debt and other long-term obligations
    1,072,207       1,072,181  
 
           
 
    2,061,756       2,003,567  
 
           
NONCURRENT LIABILITIES:
               
Accumulated deferred income taxes
    356,536       242,040  
Retirement benefits
    167,542       174,306  
Asset retirement obligations
    96,519       91,841  
Power purchase contract liability
    194,102       100,849  
Other
    49,526       46,993  
 
           
 
    864,225       656,029  
 
           
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
               
 
  $ 3,162,257     $ 2,899,001  
 
           
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

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PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
                 
    Nine Months Ended  
    September 30  
    2010     2009  
    (In thousands)  
 
               
CASH FLOWS FROM OPERATING ACTIVITIES:
               
Net Income
  $ 50,089     $ 49,307  
Adjustments to reconcile net income to net cash from operating activities-
               
Provision for depreciation
    46,146       45,074  
Amortization (deferral) of regulatory assets, net
    (22,259 )     44,090  
Deferred costs recoverable as regulatory assets
    (61,574 )     (76,953 )
Deferred income taxes and investment tax credits, net
    94,015       56,144  
Accrued compensation and retirement benefits
    7,634       6,271  
Cash collateral paid, net
    (11,760 )      
Pension trust contribution
          (60,000 )
Decrease (increase) in operating assets-
               
Receivables
    (2,584 )     3,687  
Prepayments and other current assets
    (30,034 )     (24,730 )
Increase (decrease) in operating liabilities-
               
Accounts payable
    (12,766 )     (8,988 )
Accrued taxes
    (2,245 )     (7,015 )
Accrued interest
    6,915       (2,570 )
Other
    10,127       13,392  
 
           
Net cash provided from operating activities
    71,704       37,709  
 
           
 
               
CASH FLOWS FROM FINANCING ACTIVITIES:
               
New Financing-
               
Long-term debt
          498,583  
Short-term borrowings, net
    1,771        
Redemptions and Repayments-
               
Long-term debt
          (100,000 )
Short-term borrowings, net
          (239,770 )
Common stock dividend payments
          (85,000 )
Other
    (125 )     (3,865 )
 
           
Net cash provided from financing activities
    1,646       69,948  
 
           
 
               
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Property additions
    (91,924 )     (92,070 )
Sales of investment securities held in trusts
    141,392       80,986  
Purchases of investment securities held in trusts
    (116,240 )     (91,105 )
Other
    (6,584 )     (5,482 )
 
           
Net cash used for investing activities
    (73,356 )     (107,671 )
 
           
 
               
Net change in cash and cash equivalents
    (6 )     (14 )
Cash and cash equivalents at beginning of period
    14       23  
 
           
Cash and cash equivalents at end of period
  $ 8     $ 9  
 
           
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

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COMBINED NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
1. ORGANIZATION AND BASIS OF PRESENTATION
FirstEnergy is a diversified energy company that holds, directly or indirectly, all of the outstanding common stock of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), ATSI, JCP&L, Met-Ed, Penelec, FENOC, FES and its subsidiaries FGCO and NGC, and FESC.
FirstEnergy and its subsidiaries follow GAAP and comply with the regulations, orders, policies and practices prescribed by the SEC, the FERC and, as applicable, the PUCO, the PPUC and the NJBPU. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not indicative of results of operations for any future period. In preparing the financial statements, FirstEnergy and its subsidiaries have evaluated events and transactions for potential recognition or disclosure through 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, 2009 for FirstEnergy, FES and the Utilities, as applicable. The consolidated unaudited financial statements of FirstEnergy, FES and each of the Utilities reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain prior year amounts have been reclassified to conform to the current year presentation. Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.
FirstEnergy and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary (see Note 7). Investments in affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but 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. EARNINGS PER SHARE
Basic earnings per share of common stock is computed using the weighted average of actual common shares outstanding during the respective period as the denominator. The denominator for diluted earnings per share of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. The following table reconciles basic and diluted earnings per share of common stock:
                                 
    Three Months     Nine Months  
Reconciliation of Basic and Diluted Earnings per Share   Ended September 30     Ended September 30  
of Common Stock   2010     2009     2010     2009  
    (In millions, except per share amounts)  
 
                               
Earnings available to FirstEnergy Corp.
  $ 179     $ 234     $ 599     $ 768  
 
                       
 
                               
Weighted average number of basic shares outstanding
    304       304       304       304  
Assumed exercise of dilutive stock options and awards
    1       2       1       2  
 
                       
Weighted average number of diluted shares outstanding
    305       306       305       306  
 
                       
 
                               
Basic earnings per share of common stock
  $ 0.59     $ 0.77     $ 1.97     $ 2.52  
 
                       
Diluted earnings per share of common stock
  $ 0.59     $ 0.77     $ 1.96     $ 2.51  
 
                       

 

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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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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, 2010 and December 31, 2009:
                                 
    September 30, 2010     December 31, 2009  
    Carrying     Fair     Carrying     Fair  
    Value     Value     Value     Value  
    (In millions)  
 
                               
FirstEnergy (Consolidated)
  $ 13,592     $ 14,920     $ 13,753     $ 14,502  
FES
    4,181       4,228       4,224       4,306  
OE
    1,159       1,409       1,169       1,299  
CEI
    1,853       2,144       1,873       2,032  
TE
    600       706       600       638  
JCP&L
    1,819       2,076       1,840       1,950  
Met-Ed
    742       849       842       909  
Penelec
    1,144       1,269       1,144       1,177  
The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective period. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to those of FES and the Utilities.
(B) INVESTMENTS
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.
Available-For-Sale Securities
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, 2010 and December 31, 2009:
                                                                 
    September 30, 2010(1)     December 31, 2009(2)  
    Cost     Unrealized     Unrealized     Fair     Cost     Unrealized     Unrealized     Fair  
    Basis     Gains     Losses     Value     Basis     Gains     Losses     Value  
    (In millions)  
Debt securities
                                                               
FirstEnergy
  $ 1,795     $ 73     $     $ 1,868     $ 1,727     $ 22     $     $ 1,749  
FES
    1,079       39             1,118       1,043       3             1,046  
OE
    124       4             128       55                   55  
TE
    31       1             32       72                   72  
JCP&L
    277       15             292       271       9             280  
Met-Ed
    129       8             137       120       5             125  
Penelec
    155       6             161       166       5             171  
 
                                                               
Equity securities
                                                               
FirstEnergy
  $ 261     $ 44     $     $ 305     $ 252     $ 43     $     $ 295  
JCP&L
    78       9             87       74       11             85  
Met-Ed
    122       23             145       117       23             140  
Penelec
    62       10             72       61       9             70  
(1)  
Excludes cash balances: FirstEnergy — $93 million; FES — $40 million; OE — $2 million; TE — $44 million; JCP&L — $5 million; Met-Ed — $(5) million and Penelec — $6 million.
 
(2)  
Excludes cash balances: FirstEnergy — $137 million; FES — $43 million; OE — $66 million; TE — $2 million; JCP&L — $3 million and Penelec — $23 million.

 

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Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income for the nine-month period ended September 30, 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  
                                                         
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  
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, 2010 and December 31, 2009:
                                                                 
    September 30, 2010     December 31, 2009  
    Cost     Unrealized     Unrealized     Fair     Cost     Unrealized     Unrealized     Fair  
    Basis     Gains     Losses     Value     Basis     Gains     Losses     Value  
    (In millions)  
Debt Securities
                                                               
FirstEnergy
  $ 486     $ 99     $     $ 585     $ 544     $ 72     $     $ 616  
OE
    205       60             265       217       29             246  
CEI
    340       31             371       389       43             432  
Investments in emission allowances, employee benefits and cost and equity method investments totaling $256 million as of September 30, 2010, and $264 million as of December 31, 2009 are not required to be disclosed and are therefore excluded from the amounts reported above.
Notes Receivable
The table below provides the approximate fair value and related carrying amounts of notes receivable as of September 30, 2010 and December 31, 2009. 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.
                                 
    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.
(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 where transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. FirstEnergy’s Level 1 assets and liabilities primarily consist of exchange-traded derivatives and equity securities listed on active exchanges that are held in various trusts.

 

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Level 2 — Pricing inputs are either directly or indirectly observable in the market as of the reporting date, other than quoted prices in active markets included in Level 1. FirstEnergy’s Level 2 assets and liabilities consist primarily of investments in debt securities held in various trusts and commodity forwards. Additionally, Level 2 includes those financial instruments that are valued using models or other valuation methodologies based on assumptions that are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Instruments in this category include non-exchange-traded derivatives such as forwards and certain interest rate swaps.
Level 3 — Pricing inputs include inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. FirstEnergy develops its view of the future market price of key commodities through a combination of market observation and assessment (generally for the short term) and fundamental modeling (generally for the long term). Key fundamental electricity model inputs are generally directly observable in the market or derived from publicly available historic and forecast data. Some key inputs reflect forecasts published by industry leading consultants who generally employ similar fundamental modeling approaches. Fundamental model inputs and results, as well as the selection of consultants, reflect the consensus of appropriate FirstEnergy management. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. FirstEnergy’s Level 3 instruments consist exclusively of NUG contracts.
FirstEnergy utilizes market data and assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs.
The following tables set forth financial assets and financial liabilities that are accounted for at fair value by level within the fair value hierarchy as of September 30, 2010 and December 31, 2009. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. FirstEnergy’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     $     $     $     $     $  
 
                                         

 

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    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     $     $     $     $     $  
 
                                         
                                                         
    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  
 
                                         
(1)  
NDT funds hold equity portfolios whose performance is benchmarked against the S&P 500 Index or Russell 3000 Index.
 
(2)  
Excludes $(13) million of receivables, payables and accrued income.
 
(3)  
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     $     $     $     $     $  
 
                                         

 

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    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)  
NDT funds hold equity portfolios whose performance is benchmarked against the S&P 500 Index or Russell 3000 Index.
 
(2)  
Excludes $21 million of receivables, payables and accrued income.
 
(3)  
NUG contracts are subject to regulatory accounting and do not impact earnings.
The determination of the above fair value measures takes into consideration various factors. These factors include nonperformance risk, including counterparty credit risk and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of nonperformance risk was immaterial in the fair value measurements.

 

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The following tables set forth a reconciliation of changes in the fair value of NUG contracts classified as Level 3 in the fair value hierarchy for the three and nine months ended September 30, 2010 and 2009 (in millions):
                                 
    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 )
 
                       
(1)  
Changes in fair value of NUG contracts are subject to regulatory accounting and do not impact earnings.
5. DERIVATIVE INSTRUMENTS
FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. To manage the volatility relating to these exposures, FirstEnergy uses a variety of derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used for risk management purposes. In addition to derivatives, FirstEnergy also enters into master netting agreements with certain third parties. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general management oversight for risk management activities throughout FirstEnergy. The Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practices.
FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value unless they meet the normal purchases and normal sales criteria. Derivatives that meet those criteria are accounted for at cost under the accrual method of accounting. The changes in the fair value of derivative instruments that do not meet 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 the value of the hedged item. Based on derivative contracts held 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% increase 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.
Cash Flow Hedges
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, no forward starting swap agreements were outstanding.
Total unamortized losses included in AOCL associated with prior interest rate cash flow hedges totaled $95 million ($62 million net of tax) as of September 30, 2010. Based on current estimates, approximately $11 million will be amortized to interest expense during the next twelve months. The table below provides the activity of AOCL related to interest rate cash flow hedges as of September 30, 2010 and 2009.
                                 
    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 )

 

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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.
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.
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 used in FirstEnergy’s peaking units. Heating oil futures are entered into based on expected consumption of oil and the financial risk in FirstEnergy’s coal transportation contracts. Derivative instruments are not used in quantities greater than forecasted needs. The following table summarizes the volume of FirstEnergy’s outstanding derivative transactions as of September 30, 2010:
                                 
    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

 

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The effect of derivative instruments on the consolidated statements of income and comprehensive income for the three and nine months ended September 30, 2010 and 2009, are summarized in the following tables:
                                 
    Three 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)
  $ (2 )   $     $     $ (2 )
Effective Gain (Loss) Reclassified to:(1)
                               
Purchased Power Expense
    (1 )                 (1 )
Fuel Expense
          (3 )     (1 )     (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 )
                                 
    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 )
(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 )
 
                 

 

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    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 NUG contracts are deferred for future recovery from (or refund to) customers.
Total unamortized losses included 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 derivative contracts include credit risk-related contingent features that would require FirstEnergy to post additional collateral if the credit rating for its debt were to fall below investment grade. The aggregate fair value of derivative instruments with credit risk-related contingent features that are in a liability position on September 30, 2010 was $158 million, 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.

 

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6. PENSION AND OTHER POSTRETIREMENT BENEFITS
FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and compensation levels.
FirstEnergy’s net pension and OPEB expense for the three months ended September 30, 2010 and 2009 was $20 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 million, respectively. The components of FirstEnergy’s net pension and other postretirement benefit costs (including amounts capitalized) for the three and nine months ended September 30, 2010 and 2009, consisted of the following:
                                 
    Three Months Ended     Nine Months Ended  
    September     September 30  
Pension Benefit Cost (Credit)   2010     2009     2010     2009  
    (In millions)  
Service cost
  $ 25     $ 23     $ 74     $ 66  
Interest cost
    79       79       236       239  
Expected return on plan assets
    (90 )     (86 )     (271 )     (248 )
Amortization of prior service cost
    3       3       10       10  
Recognized net actuarial loss
    47       45       141       129  
 
                       
Net periodic cost
  $ 64     $ 64     $ 190     $ 196  
 
                       
                                 
    Three Months Ended     Nine Months Ended  
    September 30     September 30  
Other Postretirement Benefit Cost (Credit)   2010     2009     2010     2009  
    (In millions)  
Service cost
  $ 2     $ 15     $ 7     $ 23  
Interest cost
    11       13       33       51  
Expected return on plan assets
    (9 )     (9 )     (27 )     (27 )
Amortization of prior service cost
    (48 )     (48 )     (144 )     (127 )
Recognized net actuarial loss
    15       15       45       46  
 
                       
Net periodic cost
  $ (29 )   $ (14 )   $ (86 )   $ (34 )
 
                       
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, 2010 and 2009 were as follows:
                                 
    Three Months Ended     Nine Months Ended  
    September 30     September 30  
Pension Benefit Cost   2010     2009     2010     2009  
    (In millions)  
FES
  $ 22     $ 19     $ 66     $ 56  
OE
    6       6       17       20  
CEI
    5       5       16       14  
TE
    2       2       5       5  
JCP&L
    6       8       19       26  
Met-Ed
    3       5       8       16  
Penelec
    5       4       14       13  
Other FirstEnergy Subsidiaries
    15       15       45       46  
 
                       
 
  $ 64     $ 64     $ 190     $ 196  
 
                       

 

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    Three Months Ended     Nine Months Ended  
    September 30     September 30  
Other Postretirement Benefit Cost (Credit)   2010     2009     2010     2009  
    (In millions)  
FES
  $ (7 )   $ (4 )   $ (20 )   $ (8 )
OE
    (6 )     (3 )     (19 )     (8 )
CEI
    (1 )           (4 )     1  
TE
          1       (1 )     2  
JCP&L
    (2 )     (2 )     (5 )     (4 )
Met-Ed
    (2 )     (1 )     (6 )     (3 )
Penelec
    (2 )     (1 )     (6 )     (2 )
Other FirstEnergy Subsidiaries
    (9 )     (4 )     (25 )     (12 )
 
                       
 
  $ (29 )   $ (14 )   $ (86 )   $ (34 )
 
                       
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 analysis to determine whether a variable interest gives FirstEnergy or its subsidiaries a controlling financial interest in a VIE. This analysis identifies the primary beneficiary of a VIE as the enterprise that has both the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. This standard also requires an ongoing reassessment of the primary beneficiary of a VIE and eliminates the quantitative approach previously required for determining whether an entity is the primary beneficiary. There was no impact to FirstEnergy or its subsidiaries as a result of the adoption of this standard.
In order to evaluate contracts under the consolidation guidance, FirstEnergy aggregated contracts into two categories based on similar risk characteristics and significance as follows:
Power Purchase Agreements
FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities may be VIEs to the extent they own a plant that sells substantially all of its output to the Utilities and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed and Penelec, maintains 21 long-term power purchase agreements with NUG entities. The agreements were entered into pursuant to the Public Utility Regulatory Policies Act of 1978. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, these entities.
FirstEnergy has determined that for all but two of these NUG entities, neither JCP&L, nor Met-Ed nor Penelec have variable interests in the entities or the entities are governmental or not-for-profit organizations that are not within the scope of consolidation consideration for VIEs. JCP&L may hold variable interests in the remaining two entities, which sell their output at variable prices that correlate to some extent with the operating costs of the plants. However, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities.
Since JCP&L has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs it incurs for power. FirstEnergy expects any above-market costs it incurs to be recovered from customers. Purchased power costs related to the two contracts that may contain a variable interest were $73 million and $58 million for the three months ended September 30, 2010, and 2009, respectively and $190 million and $173 million for the nine months ended September 30, 2010 and 2009, respectively.

 

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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.
FES and the Ohio Companies are exposed to losses under their applicable sale-leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty events that render the applicable plant worthless. Net discounted lease payments would not be payable if the casualty loss payments were made. The following table discloses each company’s net exposure to loss based upon the casualty value provisions mentioned above as of September 30, 2010:
                         
    Maximum     Discounted Lease     Net  
    Exposure     Payments, net(1)     Exposure  
    (In millions)  
FES
  $ 1,376     $ 1,185     $ 191  
OE
    672       511       161  
CEI(2)
    627       71       556  
TE(2)
    627       346       281  
(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 reaching 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 portion of the tax benefit increased FirstEnergy’s accumulated deferred income taxes. Upon completion of the federal tax examination for the 2007 tax year in the first quarter of 2009, FirstEnergy recognized $13 million in tax benefits, which favorably affected FirstEnergy’s effective tax rate. There were no material changes to FirstEnergy’s unrecognized tax benefits in the third quarter of 2009.
As of September 30, 2010, it is reasonably possible that approximately $44 million of unrecognized benefits may be resolved within the next twelve months, of which less than $1 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 consolidated 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.
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 nine months of 2009, there were no material changes to the amount of interest accrued. The net amount of accumulated interest accrued as of September 30, 2010 was $6 million, as compared to $21 million as of December 31, 2009.
As a result of the Patient Protection and Affordable Care Act and the Health Care and Education Affordability Reconciliation Act signed into law on March 23, 2010 and March 30, 2010, respectively, beginning in 2013 the tax deduction available to FirstEnergy 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 are 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 reflects 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, the Small Business Jobs Act was signed into law, which extends 50% bonus first-year depreciation for one year to 2010. Management is currently evaluating this tax election which could have a material impact on taxable income for 2010 and could increase the amount of tax refunds to be recognized in 2010 with a corresponding increase to accumulated deferred income taxes for this temporary tax item.
FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS 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.
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, outstanding guarantees and other assurances aggregated approximately $3.8 billion, consisting primarily of parental guarantees ($0.8 billion), subsidiaries’ guarantees ($2.5 billion), surety bonds and LOCs ($0.5 billion).
FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate or hedge normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for the financing or refinancing by subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties’ claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy’s guarantee enables the counterparty’s legal claim to be satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees of $0.3 billion (included in the $0.8 billion discussed above) as of September 30, 2010 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, FirstEnergy’s maximum exposure under these collateral provisions was $419 million consisting of $374 million due to a below investment grade credit rating, of which $175 million is due to an acceleration of payment or funding obligation, and $45 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 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.
Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $84 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.
In addition to guarantees and surety bonds, FES’ contracts, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions which require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ power portfolio as of September 30, 2010, and forward prices as of that date, FES has posted collateral of $244 million. 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. Depending on the volume of forward contracts and future price movements, FES could be required to post higher amounts for margining.

 

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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.
(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 SO2 and NOX 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 NOX 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, PennFuture filed a citizen suit under the CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations, in the U.S. District Court for the Western District of Pennsylvania. In July 2008, three additional complaints were filed against FGCO 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 those three complaints.
The states of New Jersey and Connecticut filed CAA citizen suits in 2007 alleging NSR violations at the Portland Generation Station against RRI Energy, Inc. (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.
In January 2009, the EPA issued a NOV to Reliant 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. alleging that “modifications” at the Homer City Power Station occurred since 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 identical allegations as 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 required 60 days prior to filing a citizen suit under the CAA. 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.
National Ambient Air Quality Standards
The EPA’s CAIR requires reductions of NOX and SO2 emissions in two phases (2009/2010 and 2015), ultimately capping SO2 emissions in affected states to 2.5 million tons annually and NOX emissions to 1.3 million tons annually. In 2008, the U.S. Court of Appeals for the District of Columbia vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” In December 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s opinion. The Court ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOX SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the “8-hour” ozone NAAQS. In July 2010, the EPA proposed the Clean Air Transport Rule (CATR) to replace CAIR, which remains in effect until the EPA finalizes CATR. CATR requires reductions of NOX and SO2 emissions in two phases (2012 and 2014), ultimately capping SO2 emissions in affected states to 2.6 million tons annually and NOX emissions to 1.3 million tons annually. The EPA proposed a preferred regulatory approach that allows trading of NOX and SO2 emission allowances between power plants located in the same state 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 NOX and SO2 emission allowances and the second eliminates trading of NOX and SO2 emission allowances in its entirety. Depending on the actions taken by the EPA with respect to CATR, the proposed MACT regulations discussed below and any future regulations that are ultimately implemented, FGCO’s future cost of compliance 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, and to finalize the regulations by November 16, 2011. Depending on the action taken by the EPA and on how any future regulations are ultimately implemented, FGCO’s future cost of compliance with MACT regulations may be substantial and changes to FGCO’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, on June 26, 2009. The Senate continues to consider a number of measures to regulate GHG emissions. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuring that 10% of electricity used in the United States comes from renewable sources by 2012, increasing to 25% by 2025, and implementing an economy-wide cap-and-trade program to reduce GHG emissions by 80% by 2050. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states, led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.

 

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In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that will require FirstEnergy to measure GHG emissions commencing in 2010 and submit reports commencing in 2011. In December 2009, the EPA released 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 until July 1, 2011 that emissions applicability threshold will only apply if PSD is triggered by non-carbon dioxide pollutants.
At the international level, the Kyoto Protocol, signed by the U.S. in 1998 but never submitted for ratification by the U.S. Senate, was intended to address global warming by reducing the amount of 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 which recognized the scientific view that the increase in global temperature should be below two degrees Celsius; include 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 establish the “Copenhagen Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. Once they have become a party to the Copenhagen Accord, developed economies, such as the European Union, Japan, Russia and the United States, would commit to quantified economy-wide emissions 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, 2009, the U.S. Court of Appeals for the Second Circuit and on October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit reversed and remanded lower court decisions that had dismissed complaints alleging damage from GHG emissions on jurisdictional grounds. However, a subsequent ruling from the U.S. Court of Appeals for the Fifth Circuit reinstated the lower court dismissal of a complaint alleging damage from GHG emissions. These cases involve common law tort claims, including public and private nuisance, alleging that GHG emissions contribute to global warming and result in property damages. While FirstEnergy is 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 regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy’s plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to FirstEnergy’s operations.
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. On 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. The EPA is developing a new regulation under Section 316(b) of the Clean Water Act consistent with the opinions of the Supreme Court and the Court of Appeals which have created significant uncertainty about the specific nature, scope and timing of the final performance standard. FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore power plant’s water intake channel to divert fish away from the plant’s water intake system. On March 15, 2010, the EPA issued a draft permit for the Bay Shore power plant requiring installation of reverse louvers in its entire water intake channel by December 31, 2014. Depending on the results of such studies and the EPA’s further rulemaking and any final action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

 

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In June 2008, the U.S. Attorney’s Office in Cleveland, Ohio advised FGCO that it is considering prosecution under the Clean Water Act and the Migratory Bird Treaty Act for three petroleum spills at the Edgewater, Lakeshore and Bay Shore plants which occurred on November 1, 2005, January 26, 2007 and February 27, 2007. FGCO is unable to predict the outcome of this matter.
Regulation of Waste Disposal
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.
On December 30, 2009, in an advanced notice of public rulemaking, the EPA said that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. On May 4, 2010, the EPA proposed two options for additional regulation 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’s future cost of compliance with any coal combustion residuals regulations which may be promulgated could be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the EPA or the states.
The Utilities have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the consolidated balance sheet as of September 30, 2010, based on estimates of the total costs of cleanup, the Utilities’ proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $105 million (JCP&L — $76 million, TE — $1 million, CEI — $1 million, FGCO — $1 million and FirstEnergy — $26 million) have been accrued through September 30, 2010. Included in the total are accrued liabilities of approximately $67 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.
(C) OTHER LEGAL PROCEEDINGS
Power Outages and Related Litigation
In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L’s territory. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages due to the outages. After various motions, rulings and appeals, the Plaintiffs’ claims for consumer fraud, common law fraud, negligent misrepresentation, strict product liability and punitive damages were dismissed, leaving only the negligence and breach of contract causes of actions. 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 for the Court’s decision.
Litigation Relating to 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 Energy and its directors and certain officers, referred 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. 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 breached 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.
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, FirstEnergy had approximately $2.0 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. FirstEnergy provides an additional $15 million parental guarantee associated with the funding of decommissioning costs for these units.
Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.
On 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. On 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.
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 power system and impose certain operating, record-keeping and reporting requirements on the Utilities and ATSI. The NERC has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including ReliabilityFirst Corporation. All of FirstEnergy’s facilities are located within the ReliabilityFirst region. FirstEnergy actively participates in the NERC and ReliabilityFirst stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by the ReliabilityFirst Corporation.
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 arise in the normal course of operations. FirstEnergy also believes that the NERC, ReliabilityFirst and the FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with new or amended standards cannot be determined at this time; however, 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 a vegetation encroachment event on a Met-Ed 230 kV line to ReliabilityFirst. 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, ReliabilityFirst issued a Notice of Enforcement to investigate the incident. FirstEnergy submitted a data response to ReliabilityFirst on September 27, 2010. At this time, FirstEnergy is unable to predict the outcome of this investigation.
(B) OHIO
The Ohio Companies operate under an Amended ESP, which expires on May 31, 2011, and 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.
On March 23, 2010, the Ohio Companies filed an application for a new ESP. 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 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

 

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system. This Rider substitutes for Rider DSI which terminates by its own terms. The Ohio Companies also agree not to collect certain amounts associated with RTEP and administrative costs associated with the move to PJM, 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 that retail customers of the Ohio Companies will not pay certain costs related to the companies’ integration into PJM, 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 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.
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.
On December 15, 2009, the Ohio Companies filed the required three year portfolio plan seeking approval for the programs they intend to implement to meet the energy efficiency and peak demand reduction requirements for the 2010-2012 period. On March 8, 2010, the Ohio Companies filed their 2009 Status Update Report with the PUCO in which they indicated compliance with the 2009 statutory energy efficiency and peak demand benchmarks as those benchmarks were amended as described above. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers. The Ohio Companies’ three year portfolio plan is still awaiting decision from the PUCO. The plan has yet to be approved by the PUCO, which is delaying the launch of the programs described in the plan. Without such approval, the Ohio Companies’ compliance with 2010 benchmarks is jeopardized and if not approved soon may require the Ohio Companies to seek an amendment to their annual benchmark requirements for 2010. Failure to comply with the benchmarks or to obtain such an amendment may subject the Companies to an assessment by the PUCO of a forfeiture.
Additionally under SB221, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they 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. 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 CEI filed an application with the PUCO to establish a new credit for all-electric customers. On March 3, 2010, the PUCO ordered that rates for the affected customers be set at a level that will provide bill impacts commensurate with charges in place on December 31, 2008 and authorized the Ohio Companies to defer incurred costs equivalent to the difference between what the affected customers would have paid under previously existing rates and what they pay with the new credit in place. Tariffs implementing this new credit went into effect on March 17, 2010. On April 15, 2010, the PUCO issued a Second Entry on Rehearing that expanded the group of customers to which the new credit would apply and authorized deferral for the associated additional amounts. The PUCO also stated that 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 rehearing of 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.

 

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(C) 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 denies the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, and directs Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructs Met-Ed and Penelec to work with the various intervening parties to file a 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 outcome 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.
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.

 

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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.
(D) NEW JERSEY
JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers, costs incurred under NUG agreements, and certain other stranded costs, exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of September 30, 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 comments in the proceeding in November 2007. A schedule for further NJBPU proceedings has not yet been set. On March 13, 2009, JCP&L filed its annual SBC Petition with the NJBPU that includes a request for a reduction in the level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009 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.

 

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(E) FERC MATTERS
PJM Transmission Rate
On 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 on 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 the reply comments. 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 their costs. Numerous parties filed responsive comments or studies on May 28, 2010 and reply comments on June 28, 2010. FirstEnergy and a number of other utilities, industrial customers and state commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. Certain eastern utilities and their state commissions supported continued socialization of these costs on a load ratio share basis. FERC is expected to act before the end of the year.
RTO Consolidation
On December 17, 2009, FERC issued an order approving, subject to certain future compliance filings, ATSI’s move to PJM. This move, which is expected to be effective on June 1, 2011, allows 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 requirements 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. Execution 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 completion of these steps secured the capacity necessary for the ATSI footprint to meet PJM’s capacity requirements.
On September 4, 2009, the PUCO opened a case 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 of the move into PJM, and certain of these matters remain outstanding and will 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.
MISO Multi-Value Project Rule Proposal
On July 15, 2010, MISO and certain MISO transmission owners jointly filed with FERC their proposed cost allocation methodology for new transmission projects. The new transmission projects—described as Multi-Value Projects (MVPs)—are a class of MTEP projects. The MISO proposes 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 expects that its 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 has requested that FERC rule on its MVP proposal by December, but has asked for an effective date for its proposal of July 16, 2011. On August 19, 2010, MISO’s Board approved the first MVP 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’s estimated allocations of the costs for the Michigan Thumb Project, where approximately $16 million in annual revenue requirements were allocated to the ATSI zone.

 

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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). 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. Numerous other parties filed pleadings on MISO’s MVP proposal. FirstEnergy is unable to predict the outcome of this matter.
11. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
In 2010, the FASB amended the Receivable Topic of the FASB Accounting Standards Codification to enhance disclosures about the credit quality of financing receivables 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 quality of its financing receivables and its allowance for credit losses. The amendment also requires an entity to disclose credit quality indicators, past due information, and modifications of its financing receivables. The amendment is effective for interim and annual reporting periods ending on or after December 15, 2010. FirstEnergy is currently evaluating the impact of adopting this standard on its financial statements.
12. SEGMENT INFORMATION
Financial information for each of FirstEnergy’s reportable segments is presented in the following table. FES and the Utilities do not have separate reportable operating segments. With the completion of transition to a fully competitive generation market in Ohio in 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 Services segment transmits and distributes electricity through FirstEnergy’s eight utility operating companies, serving 4.5 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey, and purchases power for its POLR and default service requirements in Ohio, Pennsylvania and New Jersey. Its revenues are primarily derived from the delivery of electricity within FirstEnergy’s service areas, cost recovery of regulatory assets and the sale of electric generation service to retail customers who have not selected an alternative supplier (default service) in its Ohio, Pennsylvania and New Jersey franchise areas. Its results reflect the commodity costs of securing electric generation from FES and from non-affiliated power suppliers, the net PJM and MISO transmission expenses related to the delivery of the respective generation loads and the deferral and amortization of certain fuel costs.
The Competitive Energy Services segment supplies electric power to end-use customers through retail and wholesale arrangements, including associated company power sales to meet all or a portion of the 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. This business segment controls approximately 14,000 MW of capacity and also purchases electricity to meet sales obligations. The segment’s net income is primarily derived from affiliated and non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO to deliver energy to the segment’s customers.
The other 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                      
    Delivery     Energy             Reconciling        
Three Months Ended   Services     Services     Other     Adjustments     Consolidated  
    (In millions)  
September 30, 2010
                                       
External revenues
  $ 2,757     $ 957     $ 11     $ (32 )   $ 3,693  
Internal revenues
    60       599             (659 )      
 
                             
Total revenues
    2,817       1,556       11       (691 )     3,693  
Depreciation and amortization
    287       62       6       3       358  
Investment income (loss), net
    23       28             (5 )     46  
Net interest charges
    123       30       2       12       167  
Income taxes
    137       (17 )     5       (6 )     119  
Net income (loss)
    224       (27 )           (22 )     175  
Total assets
    22,773       11,076       604       254       34,707  
Total goodwill
    5,551       24                   5,575  
Property additions
    208       255       8       (1 )     470  
 
                                       
September 30, 2009
                                       
External revenues
  $ 2,942       490       6       (30 )     3,408  
Internal revenues
          617             (617 )      
 
                             
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  
Depreciation and amortization
    888       194       25       7       1,114  
Investment income (loss), net
    75       42             (24 )     93  
Net interest charges
    369       94       4       39       506  
Income taxes
    295       106       (14 )     (23 )     364  
Net income (loss)
    481       174       (3 )     (72 )     580  
Total assets
    22,773       11,076       604       254       34,707  
Total goodwill
    5,551       24                   5,575  
Property additions
    546       860       18       43       1,467  
 
                                       
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.

 

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13. SUPPLEMENTAL GUARANTOR INFORMATION
On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has fully, unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES’ lease guaranty. This transaction is classified as an operating lease under GAAP for FES and FirstEnergy and as a financing for FGCO.
The condensed consolidating statements of income for the three month and nine month periods ended September 30, 2010 and 2009, consolidating balance sheets as of September 30, 2010 and December 31, 2009 and consolidating statements of cash flows for the nine months ended September 30, 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.

 

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FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
                                         
For the Three Months Ended September 30, 2010   FES     FGCO     NGC     Eliminations     Consolidated  
    (In thousands)  
 
REVENUES
  $ 1,540,885     $ 645,001     $ 380,542     $ (1,012,751 )   $ 1,553,677  
 
                             
 
                                       
EXPENSES:
                                       
Fuel
    13,403       329,009       48,675             391,087  
Purchased power from affiliates
    1,058,965       13,404       56,763       (1,012,751 )     116,381  
Purchased power from non-affiliates
    411,084                         411,084  
Other operating expenses
    84,169       97,322       116,112       12,190       309,793  
Provision for depreciation
    752       23,845       36,005       (1,304 )     59,298  
General taxes
    6,216       8,875       6,713             21,804  
Impairment of long-lived assets
          291,934                   291,934  
 
                             
Total expenses
    1,574,589       764,389       264,268       (1,001,865 )     1,601,381  
 
                             
 
                                       
OPERATING INCOME (LOSS)
    (33,704 )     (119,388 )     116,274       (10,886 )     (47,704 )
 
                             
 
                                       
OTHER INCOME (EXPENSE):
                                       
Investment income
    256       396       29,243             29,895  
Miscellaneous income (expense), including net income from equity investees
    5,707       2,562       49       (3,553 )     4,765  
Interest expense — affiliates
    (60 )     (2,021 )     (416 )           (2,497 )
Interest expense — other
    (24,158 )     (26,243 )     (15,028 )     15,885       (49,544 )
Capitalized interest
    95       19,024       3,836             22,955  
 
                             
Total other income (expense)
    (18,160 )     (6,282 )     17,684       12,332       5,574  
 
                             
 
                                       
INCOME BEFORE INCOME TAXES
    (51,864 )     (125,670 )     133,958       1,446       (42,130 )
 
                                       
INCOME TAXES (BENEFITS)
    (15,138 )     (44,364 )     51,600       2,498       (5,404 )
 
                             
 
                                       
NET INCOME (LOSS)
  $ (36,726 )   $ (81,306 )   $ 82,358     $ (1,052 )   $ (36,726 )
 
                             

 

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FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
                                         
For the Nine Months Ended September 30, 2010   FES     FGCO     NGC     Eliminations     Consolidated  
    (In thousands)  
 
                                       
REVENUES
  $ 4,203,610     $ 1,793,986     $ 1,145,795     $ (2,886,947 )   $ 4,256,444  
 
                             
 
                                       
EXPENSES:
                                       
Fuel
    25,768       910,739       125,212             1,061,719  
Purchased power from affiliates
    2,940,360       25,646       167,173       (2,886,947 )     246,232  
Purchased power from non-affiliates
    1,160,119                         1,160,119  
Other operating expenses
    218,278       289,638       371,882       36,568       916,366  
Provision for depreciation
    2,253       77,838       109,364       (3,920 )     185,535  
General taxes
    17,432       32,702       20,688             70,822  
Impairment charges of long-lived assets
          293,767                   293,767  
 
                             
Total expenses
    4,364,210       1,630,330       794,319       (2,854,299 )     3,934,560  
 
                             
 
                                       
OPERATING INCOME (LOSS)
    (160,600 )     163,656       351,476       (32,648 )     321,884  
 
                             
 
                                       
OTHER INCOME (EXPENSE):
                                       
Investment income
    3,964       531       39,483             43,978  
Miscellaneous income (expense), including net income from equity investees
    323,371       1,638       50       (314,591 )     10,468  
Interest expense — affiliates
    (179 )     (5,917 )     (1,266 )           (7,362 )
Interest expense — other
    (71,793 )     (80,548 )     (46,152 )     47,933       (150,560 )
Capitalized interest
    293       54,930       11,327             66,550  
 
                             
Total other income (expense)
    255,656       (29,366 )     3,442       (266,658 )     (36,926 )
 
                             
 
                                       
INCOME BEFORE INCOME TAXES
    95,056       134,290       354,918       (299,306 )     284,958  
 
                                       
INCOME TAXES (BENEFITS)
    (82,069 )     52,144       130,163       7,595       107,833  
 
                             
 
                                       
NET INCOME
  $ 177,125     $ 82,146     $ 224,755     $ (306,901 )   $ 177,125  
 
                             

 

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FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
                                         
For the Three Months Ended September 30, 2009   FES     FGCO     NGC     Eliminations     Consolidated  
    (In thousands)  
 
                                       
REVENUES
  $ 1,087,991     $ 477,679     $ 170,129     $ (631,227 )   $ 1,104,572  
 
                             
 
                                       
EXPENSES:
                                       
Fuel
    9,278       241,953       43,462             294,693  
Purchased power from 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  
 
                             

 

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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  
 
                             

 

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FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)
                                         
As of September 30, 2010   FES     FGCO     NGC     Eliminations     Consolidated  
    (In thousands)  
ASSETS
                                       
 
                                       
CURRENT ASSETS:
                                       
Cash and cash equivalents
  $     $ 1     $ 9     $     $ 10  
Receivables-
                                       
Customers
    325,265                         325,265  
Associated companies
    299,222       193,951       112,523       (335,710 )     269,986  
Other
    34,052       4,831       18,524             57,407  
Notes receivable from associated companies
    10,100       329,461       162,087             501,648  
Materials and supplies, at average cost
    28,411       301,761       223,871             554,043  
Prepayments and other
    191,423       9,669       2,973             204,065  
 
                             
 
    888,473       839,674       519,987       (335,710 )     1,912,424  
 
                             
 
                                       
PROPERTY, PLANT AND EQUIPMENT:
                                       
In service
    94,787       4,640,027       5,313,456       (385,006 )     9,663,264  
Less — Accumulated provision for depreciation
    16,209       2,173,661       2,098,927       (174,416 )     4,114,381  
 
                             
 
    78,578       2,466,366       3,214,529       (210,590 )     5,548,883  
Construction work in progress
    7,523       2,221,270       507,842             2,736,635  
 
                             
 
    86,101       4,687,636       3,722,371       (210,590 )     8,285,518  
 
                             
 
                                       
INVESTMENTS:
                                       
Nuclear plant decommissioning trusts
                1,158,376             1,158,376  
Investment in associated companies
    4,825,221                   (4,825,221 )      
Other
    560       6,639       201             7,400  
 
                             
 
    4,825,781       6,639       1,158,577       (4,825,221 )     1,165,776  
 
                             
 
                                       
DEFERRED CHARGES AND OTHER ASSETS:
                                       
Accumulated deferred income taxes
    71,165       402,397             (470,205 )     3,357  
Customer intangibles
    127,420                         127,420  
Goodwill
    24,248                         24,248  
Property taxes
          27,811       22,314             50,125  
Unamortized sale and leaseback costs
                      61,934       61,934  
Other
    142,039       75,033       7,842       (60,582 )     164,332  
 
                             
 
    364,872       505,241       30,156       (468,853 )     431,416  
 
                             
 
  $ 6,165,227     $ 6,039,190     $ 5,431,091     $ (5,840,374 )   $ 11,795,134  
 
                             
 
                                       
LIABILITIES AND CAPITALIZATION
                                       
 
                                       
CURRENT LIABILITIES:
                                       
Currently payable long-term debt
  $ 765     $ 487,357     $ 927,772     $ (19,102 )   $ 1,396,792  
Short-term borrowings-
                                       
Associated companies
          9,642                   9,642  
Other
    100,000                         100,000  
Accounts payable-
                                       
Associated companies
    305,726       244,383       227,328       (305,419 )     472,018  
Other
    95,287       109,641                   204,928  
Accrued taxes
    1,821       46,889       56,535       (45,823 )     59,422  
Other
    253,368       110,964       28,383       38,109       430,824  
 
                             
 
    756,967       1,008,876       1,240,018       (332,235 )     2,673,626  
 
                             
 
                                       
CAPITALIZATION:
                                       
Common stockholder’s equity
    3,730,964       2,443,222       2,362,711       (4,805,933 )     3,730,964  
Long-term debt and other long-term obligations
    1,518,779       2,053,532       506,533       (1,259,694 )     2,819,150  
 
                             
 
    5,249,743       4,496,754       2,869,244       (6,065,627 )     6,550,114  
 
                             
 
                                       
NONCURRENT LIABILITIES:
                                       
Deferred gain on sale and leaseback transaction
                      967,583       967,583  
Accumulated deferred income taxes
                410,095       (410,095 )      
Accumulated deferred investment tax credits
          34,050       21,217             55,267  
Asset retirement obligations
          26,395       851,127             877,522  
Retirement benefits
    36,528       192,251                   228,779  
Property taxes
          27,811       22,314             50,125  
Lease market valuation liability
          228,119                   228,119  
Other
    121,989       24,934       17,076             163,999  
 
                             
 
    158,517       533,560       1,321,829       557,488       2,571,394  
 
                             
 
  $ 6,165,227     $ 6,039,190     $ 5,431,091     $ (5,840,374 )   $ 11,795,134  
 
                             

 

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

 

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FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
                                         
For the Nine Months Ended September 30, 2010   FES     FGCO     NGC     Eliminations     Consolidated  
    (In thousands)  
 
                                       
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES
  $ (289,503 )   $ 402,332     $ 520,272     $ (9,174 )   $ 623,927  
 
                             
 
                                       
CASH FLOWS FROM FINANCING ACTIVITIES:
                                       
New Financing-
                                       
Long-term debt
          249,520                   249,520  
Short-term borrowings, net
          405                   405  
Redemptions and Repayments-
                                       
Long-term debt
    (599 )     (261,965 )     (42,949 )     9,174       (296,339 )
Other
    (459 )     (237 )     (102 )           (798 )
 
                             
Net cash used for financing activities
    (1,058 )     (12,277 )     (43,051 )     9,174       (47,212 )
 
                             
 
                                       
CASH FLOWS FROM INVESTING ACTIVITIES:
                                       
Property additions
    (5,497 )     (417,146 )     (378,595 )           (801,238 )
Proceeds from asset sales
          117,213                   117,213  
Sales of investment securities held in trusts
                1,478,086             1,478,086  
Purchases of investment securities held in trusts
                (1,511,273 )           (1,511,273 )
Loans from (to) associated companies, net
    406,304       (88,625 )     (14,224 )           303,455  
Customer acquisition costs
    (110,073 )                       (110,073 )
Leasehold improvement payments to associated companies
                (51,204 )           (51,204 )
Other
    (173 )     (1,499 )     (11 )           (1,683 )
 
                             
Net cash provided from (used for) investing activities
    290,561       (390,057 )     (477,221 )           (576,717 )
 
                             
 
                                       
Net change in cash and cash equivalents
          (2 )                 (2 )
Cash and cash equivalents at beginning of period
          3       9             12  
 
                             
Cash and cash equivalents at end of period
  $     $ 1     $ 9     $     $ 10  
 
                             

 

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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.

 

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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. 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 in the third quarter of 2010 were $179 million, or basic and diluted earnings of $0.59 per share of common stock, compared with $234 million, or basic and diluted earnings of $0.77 per share of common stock in the third quarter of 2009. Results in 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.
                 
    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  
 
           
Pending Merger
As previously disclosed, on February 10, 2010, FirstEnergy entered into an Agreement and Plan of Merger, subsequently amended on June 4, 2010, (Merger Agreement), with Element Merger Sub. Inc., 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.
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 in the merger and the other transactions contemplated by the Merger Agreement and approved the amendment of FirstEnergy’s amended articles of incorporation 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% voted 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.

 

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Pursuant to the Merger Agreement, completion of the merger remains conditioned upon, among other things, 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
On May 11, 2010, FirstEnergy and Allegheny Energy filed an application with FERC for approval of their proposed merger. Under the Federal Power Act, FERC has 180 days 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. FERC is expected to complete its review in sufficient time to meet the anticipated merger closing schedule in the first half of 2011.
State Regulatory Merger Filings
On September 9, 2010, the VSCC approved a petition for the FirstEnergy-Allegheny Energy merger.
Pennsylvania Settlement
On October 25, 2010, FirstEnergy and Allegheny Energy filed a comprehensive settlement with the PPUC that addresses issues raised by 18 of the parties to the merger. The filing includes additional commitments related to employment levels, including a five-year commitment to maintain at least 800 jobs 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.
Hart-Scott-Rodino (HSR) Act Filings
On May 25, 2010, FirstEnergy and Allegheny Energy made HSR filings with the DOJ and Federal Trade Commission. On June 24, 2010, FirstEnergy and Allegheny Energy each received a request for additional information from the DOJ. FirstEnergy and Allegheny Energy continue to cooperate with the DOJ and expect DOJ to complete its review in sufficient time to meet the anticipated merger closing schedule in the first half of 2011.
Financial Matters
Financing Activities
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.
On October 1, 2010, FES completed the refinancing and remarketing of six series of PCRBs totaling $313 million. These series of PCRBs were converted from a variable interest rate to a fixed long term interest rate of 3.375% per-annum and are subject to mandatory purchase on July 1, 2015.
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.

 

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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-Ed and Penelec Default Service Plan
On October 20, 2010, the PPUC approved the results of the final of four auctions held to procure the default service requirements for Met-Ed and Penelec customers who choose not to shop with an alternative supplier. For the five-month period of January 1, 2011 to May 31, 2011, the tranche-weighted average prices ($/MWh) for Met-Ed’s residential and commercial classes were $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.
FIRSTENERGY’S BUSINESS
FirstEnergy is a diversified energy company headquartered in Akron, Ohio, that operates primarily through two core business segments (see Results of Operations).
   
Energy Delivery Services transmits and distributes electricity through our eight utility operating companies, serving 4.5 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey and purchases power for its POLR and default service requirements in Ohio, Pennsylvania and New Jersey. Its revenues are primarily derived from the delivery of electricity within our service areas, cost recovery of regulatory assets and the sale of electric generation service to retail customers who have not selected an alternative supplier (default service) in its Ohio, Pennsylvania and New Jersey franchise areas. Its results reflect the commodity costs of securing electric generation from FES and from non-affiliated power suppliers, the net PJM and MISO transmission expenses related to the delivery of the respective generation loads and the deferral and amortization of certain fuel costs.
   
Competitive Energy Services supplies electric power to end-use customers through retail and wholesale arrangements, including associated company power sales to meet all or a portion of the POLR and default service requirements of our Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Maryland, Michigan and New Jersey. This business segment controls approximately 14,000 MW of capacity and also purchases electricity to meet sales obligations. The segment’s net income is primarily derived from affiliated and non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power, net transmission (including congestion) and ancillary costs charged by PJM and MISO to deliver energy to the segment’s customers.

 

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RESULTS OF OPERATIONS
The financial results discussed below include revenues and expenses from transactions among FirstEnergy’s business segments. A reconciliation of segment financial results is provided in Note 12 to the consolidated financial statements. Earnings available to FirstEnergy by major business segment were as follows:
                                                 
    Three Months Ended     Nine Months Ended  
    September 30     September 30  
                    Increase                     Increase  
    2010     2009     (Decrease)     2010     2009     (Decrease)  
    (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 )
Other and reconciling adjustments*
    (18 )     (97 )     79       (56 )     (131 )     75  
 
                                   
Total
  $ 179     $ 234     $ (55 )   $ 599     $ 768     $ (169 )
 
                                   
 
                                               
Basic Earnings Per Share
  $ 0.59     $ 0.77     $ (0.18 )   $ 1.97     $ 2.52     $ (0.55 )
Diluted Earnings Per Share
  $ 0.59     $ 0.77     $ (0.18 )   $ 1.96     $ 2.51     $ (0.55 )
     
*  
Consists primarily of interest expense related to holding company debt, corporate support services revenues and expenses, noncontrolling interests and the elimination of intersegment transactions.
Summary of Results of Operations — Third Quarter 2010 Compared with Third Quarter 2009
Financial results for FirstEnergy’s major business segments in the third quarter of 2010 and 2009 were as follows:
                                 
    Energy     Competitive     Other and        
    Delivery     Energy     Reconciling     FirstEnergy  
Third Quarter 2010 Financial Results   Services     Services     Adjustments     Consolidated  
    (In millions)  
Revenues:
                               
External
                               
Electric
  $ 2,609     $ 905     $     $ 3,514  
Other
    148       52       (21 )     179  
Internal
    60       599       (659 )      
 
                       
Total Revenues
    2,817       1,556       (680 )     3,693  
 
                       
 
                               
Expenses:
                               
Fuel
          401       (1 )     400  
Purchased power
    1,473       470       (659 )     1,284  
Other operating expenses
    422       347       (31 )     738  
Provision for depreciation
    111       62       9       182  
Amortization of regulatory assets
    176                   176  
Deferral of new regulatory assets
                       
Impairment of long lived assets
          292             292  
General taxes
    174       26       6       206  
 
                       
Total Expenses
    2,356       1,598       (676 )     3,278  
 
                       
 
                               
Operating Income
    461       (42 )     (4 )     415  
 
                       
Other Income (Expense):
                               
Investment income
    23       28       (5 )     46  
Interest expense
    (125 )     (53 )     (30 )     (208 )
Capitalized interest
    2       23       16       41  
 
                       
Total Other Expense
    (100 )     (2 )     (19 )     (121 )
 
                       
 
                               
Income Before Income Taxes
    361       (44 )     (23 )     294  
Income taxes
    137       (17 )     (1 )     119  
 
                       
Net Income (Loss)
    224       (27 )     (22 )     175  
Loss attributable to noncontrolling interest
                (4 )     (4 )
 
                       
Earnings available to FirstEnergy Corp.
  $ 224     $ (27 )   $ (18 )   $ 179  
 
                       

 

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    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  
    (In millions)  
Revenues:
                               
External
                               
Electric
  $ (195 )   $ 461     $     $ 266  
Other
    10       6       3       19  
Internal
    60       (18 )     (42 )      
 
                       
Total Revenues
    (125 )     449       (39 )     285  
 
                       
 
                               
Expenses:
                               
Fuel
          99       (1 )     98  
Purchased power
    (252 )     265       (42 )     (29 )
Other operating expenses
    56       16       1       73  
Provision for depreciation
    (1 )     (7 )     2       (6 )
Amortization of regulatory assets
    (85 )                 (85 )
Deferral of new regulatory assets
                       
Impairment of long lived assets
          292             292  
General taxes
    12       (1 )     3       14  
 
                       
Total Expenses
    (270 )     664       (37 )     357  
 
                       
 
                               
Operating Income
    145       (215 )     (2 )     (72 )
 
                       
Other Income (Expense):
                               
Investment income
    (23 )     (131 )     9       (145 )
Interest expense
    (9 )     (7 )     163       147  
Capitalized interest
    1       5             6  
 
                       
Total Other Expense
    (31 )     (133 )     172       8  
 
                       
 
                               
Income Before Income Taxes
    114       (348 )     170       (64 )
Income taxes
    38       (138 )     91       (9 )
 
                       
Net Income (Loss)
    76       (210 )     79       (55 )
Loss attributable to noncontrolling interest
                       
 
                       
Earnings available to FirstEnergy Corp.
  $ 76     $ (210 )   $ 79     $ (55 )
 
                       

 

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Energy Delivery Services — Third Quarter 2010 Compared with Third Quarter 2009
Net income increased by $76 million in the third quarter of 2010, compared to the third quarter of 2009, primarily due to higher distribution revenues. Lower generation revenues were offset by lower purchased power expenses.
Revenues -
The decrease in total revenues resulted from the following sources:
                         
    Three Months        
    Ended September 30     Increase  
Revenues by Type of Service   2010     2009     (Decrease)  
    (In millions)  
Distribution services
  $ 1,041     $ 915     $ 126  
 
                 
Generation sales:
                       
Retail
    1,266       1,551       (285 )
Wholesale
    231       195       36  
 
                 
Total generation sales
    1,497       1,746       (249 )
 
                 
Transmission
    223       232       (9 )
Other
    56       49       7  
 
                 
Total Revenues
  $ 2,817     $ 2,942     $ (125 )
 
                 
The increase in distribution service revenues reflected an $88 million increase due to higher sales volumes and a $38 million increase due to a change in prices. The increase in distribution deliveries by customer class is summarized in the following table:
         
Electric Distribution KWH Deliveries        
Residential
    19 %
Commercial
    5 %
Industrial
    11 %
 
     
Total Distribution KWH Deliveries
    12 %
 
     
Higher deliveries to residential and commercial customers reflected increased weather-related usage in the third quarter of 2010, as cooling degree days increased by 60% from the same period in 2009. The increase in distribution deliveries to industrial customers was primarily due to recovering economic conditions in FirstEnergy’s service territory compared to the third quarter of 2009. In the industrial sector, KWH deliveries increased to major automotive customers (14%), 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.
The following table summarizes the price and volume factors contributing to the $249 million decrease in generation revenues in the third quarter of 2010 compared to the third quarter of 2009:
         
    Increase  
Source of Change in Generation Revenues   (Decrease)  
    (In millions)  
Retail:
       
Effect of 19.8% decrease in sales volumes
  $ (307 )
Change in prices
    22  
 
     
 
    (285 )
 
     
 
       
Wholesale:
       
Effect of 3.1% increase in sales volumes
    6  
Change in prices
    30  
 
     
 
    36  
 
     
Net Decrease in Generation Revenues
  $ (249 )
 
     

 

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The decrease in retail generation sales volumes was primarily due to an increase in customer shopping in the Ohio Companies’ service territories in the third 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 for the Ohio Companies increased to 64% in the third quarter of 2010 from 21% in the third quarter 2009.
The increase in wholesale generation revenues reflected increased capacity sales by Met-Ed and Penelec in the PJM market.
Expenses -
Total expenses decreased by $270 million due to the following:
   
Purchased power costs were $252 million lower in the third quarter of 2010 due to a decrease in volumes needed to serve the lower sales volumes. 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 from the termination of a third-party supply contract for Met-Ed and Penelec in January 2010 and from the above described increase in customer shopping in the Ohio Companies’ service territories.
   
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 replacement of Met-Ed’s and Penelec’s terminated third-party contract with supply from FES.
         
    Increase  
Source of Change in Purchased Power   (Decrease)  
    (In millions)  
Purchases from non-affiliates:
       
Change due to increased unit costs
  $ 155  
Change due to decreased volumes
    (443 )
 
     
 
    (288 )
 
     
Purchases from FES:
       
Change due to decreased unit costs
    (61 )
Change due to increased volumes
    45  
 
     
 
    (16 )
 
     
         
Decrease in costs deferred
    52  
 
     
Net Decrease in Purchased Power Costs
  $ (252 )
 
     
   
Transmission costs increased by $87 million in the third quarter of 2010 primarily due to higher PJM network transmission expenses and congestion costs for Met-Ed and Penelec. 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 general costs, including labor and employee benefit expenses, decreased by $28 million due to restructuring 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 by $10 million in the third quarter of 2010 compared to the third quarter of 2009.
   
Energy efficiency program costs increased $16 million in the third quarter of 2010 compared to the third quarter of 2009.

 

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Economic development costs associated with the Ohio Companies’ ESP increased by $10 million in the third quarter of 2010.
   
Amortization of regulatory assets decreased $85 million in the third quarter of 2010 principally due to lower net MISO and PJM transmission cost amortization compared to the third quarter of 2009.
   
General taxes increased $12 million primarily due to higher gross receipts taxes in the third quarter of 2010.
Other Expense -
Other expense increased $31 million in the third quarter of 2010 compared to the third quarter of 2009 due primarily to lower investment income related to OE’s and TE’s nuclear decommissioning trusts ($23 million) and higher interest expense associated with debt issuances by the Utilities since the third quarter of 2009 ($8 million).
Competitive Energy Services — Third Quarter 2010 Compared with Third Quarter 2009
Net income decreased by $210 million in the third quarter of 2010, compared to the third quarter 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 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.
Revenues -
Total revenues increased $449 million in the third quarter of 2010 primarily due to growth in direct and government aggregation sales and POLR sales volumes, partially offset by a decline in wholesale sales.
The increase in total revenues resulted from the following sources:
                         
    Three Months        
    Ended September 30     Increase  
Revenues by Type of Service   2010     2009     (Decrease)  
    (In millions)  
Direct and Government Aggregation
  $ 717     $ 232     $ 485  
POLR
    652       636       16  
Wholesale
    136       192       (56 )
Transmission
    22       17       5  
Other
    29       30       (1 )
 
                 
Total Revenues
  $ 1,556     $ 1,107     $ 449  
 
                 
The increase in direct and government aggregation revenues of $485 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 1.2 million residential and small commercial customers at the end of September 2010 compared to 500,000 such customers at the end of September 2009. In addition, sales to residential and small commercial customers were bolstered by weather in the delivery area that was 60% warmer than in 2009.
The increase in POLR revenues of $16 million was due to higher sales volumes to the Pennsylvania Companies and non-associated companies, partially offset by decreased sales volumes to the Ohio Companies and lower unit prices to both the Ohio Companies and the Pennsylvania Companies. The 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 the third quarter of 2009.
Wholesale revenues decreased $56 million due to reduced volumes and lower wholesale prices. The lower sales volumes were a result of using available capacity to serve increased retail sales 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 marked 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.

 

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The following tables summarize the price and volume factors contributing to changes in revenues:
         
    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 Wholesale Revenues   (Decrease)  
    (In millions)  
POLR:
       
Effect of 8.6% increase in sales volumes
  $ 55  
Change in prices
    (39 )
 
     
 
    16  
 
     
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 million due primarily to higher MISO congestion revenue.
Expenses -
Total expenses increased $664 million in the third quarter of 2010 due to the following:
   
Fuel costs increased $99 million primarily due to increased volumes, partially offset by unit prices. Volumes increased due to higher generation at the fossil units. Unit prices declined primarily due to coal blend changes partially offset by increased coal transportation expenses and higher nuclear fuel unit prices following the refueling outages that occurred in 2009.
   
Purchased power costs increased $265 million due primarily to higher volumes purchased ($246 million) and a power contract mark-to-market adjustment ($26 million), partially offset by lower unit costs ($7 million). The increase in volume primarily relates to the assumption of a 1,300 MW third party contract from Met-Ed and Penelec.
   
Fossil operating costs decreased $16 million due primarily to lower staffing levels, more capital related work and reduced coal storage limitation charges.
   
Nuclear operating costs decreased $2 million due primarily to lower labor and related benefits, partially offset by higher professional and contractor costs in connection with refueling outages.
   
Transmission expenses increased $4 million due primarily to increases in MISO of $46 million from higher network, ancillary and congestion costs, partially offset by lower PJM transmission expenses of $42 million due to lower congestion costs.
   
Other expenses increased $314 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 third quarter of 2010 was $133 million higher than the third quarter of 2009, primarily due to a decrease in nuclear decommissioning trust investment income ($131 million) and a $2 million increase in net interest expense from new long-term debt issued by FES in August 2009 combined with the restructuring of existing PCRBs.

 

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Other — Third Quarter of 2010 Compared with Third Quarter 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 $79 million increase in earnings available to FirstEnergy in the third quarter 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 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 expense ($91 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.

 

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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        
Residential
    7 %
Commercial
    3 %
Industrial
    10 %
 
     
Total Distribution KWH Deliveries
    7 %
 
     
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 liabilities that have been deferred because it is probable such amounts will be returned to customers through future regulated rates. The following table provides the balance of regulatory assets by Company as of September 30, 2010 and December 31, 2009 and changes during the nine months then ended:
                         
    September 30,     December 31,     Increase  
Regulatory Assets   2010     2009     (Decrease)  
    (In millions)  
OE
  $ 413     $ 465     $ (52 )
CEI
    420       546       (126 )
TE
    74       70       4  
JCP&L
    722       888       (166 )
Met-Ed
    400       357       43  
Penelec
    203       9       194  
Other
    14       21       (7 )
 
                 
Total
  $ 2,246     $ 2,356     $ (110 )
 
                 
The following table provides information about the composition of regulatory assets as of September 30, 2010 and December 31, 2009 and the changes during the nine months then ended:
                         
    September 30,     December 31,     Increase  
Regulatory Assets by Source   2010     2009     (Decrease)  
    (In millions)  
Regulatory transition costs
  $ 1,168     $ 1,100     $ 68  
Customer shopping incentives
    26       154       (128 )
Customer receivables for future income taxes
    330       329       1  
Loss on reacquired debt
    50       51       (1 )
Employee postretirement benefits
    17       23       (6 )
Nuclear decommissioning, decontamination and spent fuel disposal costs
    (173 )     (162 )     (11 )
Asset removal costs
    (238 )     (231 )     (7 )
MISO/PJM transmission costs
    194       148       46  
Deferred generation costs
    393       369       24  
Distribution costs
    392       482       (90 )
Other
    87       93       (6 )
 
                 
Total
  $ 2,246     $ 2,356     $ (110 )
 
                 
Regulatory assets that do not earn a current return totaled approximately $181 million as of September 30, 2010 (JCP&L — $40 million, Met-Ed — $124 million, Penelec — $9 million and CEI $5 million). Regulatory assets not earning a current return (primarily for certain regulatory transition costs and employee postretirement benefits) are expected to be recovered by 2014 for JCP&L and by 2020 for Met-Ed and Penelec.
Competitive Energy Services — First Nine Months 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 volatility of these contracts through the end of 2011 and resulted in wholesale revenues of $13 million in 2010.
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, FirstEnergy had cash and cash equivalents of approximately $632 million available to fund investments, operations and capital expenditures. To fund liquidity and capital requirements for the balance of 2010 and beyond, FirstEnergy will 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, 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 ability to fund current liquidity and 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 as the transition to competitive generation markets continues, operational excellence, retail strategy execution, well-positioned generation fleet, no speculative trading operations, appropriate long-term commodity hedging positions, manageable capital expenditure program, well funded pension, 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.
As of September 30, 2010, 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. Currently payable long-term debt as of September 30, 2010, included the following (in millions):
         
Currently Payable Long-term Debt        
PCRBs supported by bank LOCs(1)
  $ 1,318  
FGCO and NGC unsecured PCRBs(1)
    90  
Penelec FMBs(2)
    24  
NGC collateralized lease obligation bonds
    50  
Sinking fund requirements
    34  
Other notes(3)
    74  
 
     
 
  $ 1,590  
 
     
     
(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 of short-term borrowings as of September 30, 2010 and $1.2 billion as of December 31, 2009. FirstEnergy’s available liquidity as of October 22, 2010, is summarized in the following table:
                                 
                            Available  
Company   Type     Maturity     Commitment     Liquidity  
                (In millions)  
FirstEnergy(1)
  Revolving   Aug. 2012     $ 2,750     $ 1,650  
FirstEnergy Solutions
  Term loan   Mar. 2011       100        
Ohio and Pennsylvania Companies
  Receivables financing     Various (2)     395       245  
 
                           
 
          Subtotal     $ 3,245     $ 1,895  
 
          Cash             911  
 
                           
 
          Total     $ 3,245     $ 2,806  
 
                           
     
(1)  
FirstEnergy Corp. and subsidiary borrowers.
 
(2)  
Ohio — $250 million matures March 30, 2011; Pennsylvania — $145 million matures December 17, 2010 with optional extension terms.

 

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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 Facility
FirstEnergy has the capability to request an increase in the total commitments available under the $2.75 billion revolving credit facility (included in the borrowing capability table above) up to a maximum of $3.25 billion, subject to the discretion of each lender to provide additional commitments. A total of 25 banks participate in the facility, with no one bank having more than 7.3% of the total commitment. Commitments under the facility are available until August 24, 2012, unless the lenders agree, at the request of the borrowers, to an unlimited number of additional one-year extensions. Generally, borrowings under the facility must be repaid within 364 days. Available amounts for each borrower are subject to a specified sub-limit, as well as applicable regulatory and other limitations.
The following table summarizes the borrowing sub-limits for each borrower under the facility, as well as the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations as of September 30, 2010:
                 
    Revolving     Regulatory and  
    Credit Facility     Other Short-Term  
Borrower   Sub-Limit     Debt Limitations  
    (In millions)  
FirstEnergy
  $ 2,750     $ (1)
FES
    1,000       (1)
OE
    500       500  
Penn
    50       34 (2)
CEI
    250 (3)     500  
TE
    250 (3)     500  
JCP&L
    425       410 (2)
Met-Ed
    250       300 (2)
Penelec
    250       300 (2)
ATSI
    50 (4)     50  
     
(1)  
No regulatory approvals, statutory or charter limitations applicable.
 
(2)  
Excluding amounts that may be borrowed under the regulated companies’ money pool.
 
(3)  
Borrowing sub-limits for CEI and TE may be increased to up to $500 million by delivering notice to the administrative agent that such borrower has senior unsecured debt ratings of at least BBB by S&P and Baa2 by Moody’s.
 
(4)  
The borrowing sub-limit for ATSI may be increased up to $100 million by delivering notice to the administrative agent that ATSI has received regulatory approval to have short-term borrowings up to the same amount.
Under the revolving credit facility, borrowers may request the issuance of LOCs expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit.
The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%, measured at the end of each fiscal quarter. As of September 30, 2010, 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
    57.7 %
JCP&L
    34.4 %
Met-Ed
    37.6 %
Penelec
    51.8 %
ATSI
    48.8 %

 

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As of September 30, 2010, FirstEnergy could issue additional debt of approximately $2.9 billion, or recognize a reduction in equity of approximately $1.6 billion, and remain within the limitations of the financial covenants required by its revolving credit facility.
The revolving credit facility does not contain provisions that either restrict the ability to borrow or accelerate repayment of outstanding advances as a result of any change in credit ratings. Pricing is defined in “pricing grids,” whereby the cost of funds borrowed under the facility is related to the credit ratings of the company borrowing the funds.
FirstEnergy Money Pools
FirstEnergy’s regulated companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy’s unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first nine months of 2010 was 0.53% per annum for the regulated companies’ money pool and 0.60% per annum for the unregulated companies’ money pool.
Pollution Control Revenue Bonds
As of September 30, 2010, FirstEnergy’s currently payable long-term debt included approximately $1.3 billion (FES — $1.2 billion, Met-Ed — $29 million and Penelec — $45 million) of variable interest rate PCRBs, the bondholders of which are entitled to the benefit of irrevocable direct pay bank LOCs. The interest rates on the PCRBs are reset daily or weekly. Bondholders can tender their PCRBs for mandatory purchase prior to maturity with the purchase price payable from remarketing proceeds or, if the PCRBs are not successfully remarketed, by drawings on the irrevocable direct pay LOCs. The subsidiary obligor is required to reimburse the applicable LOC bank for any such drawings or, if the LOC bank fails to honor its LOC for any reason, must itself pay the purchase price.
The LOCs for FirstEnergy variable interest rate PCRBs were issued by the following banks as of September 30, 2010:
                 
    Aggregate LOC         Reimbursements of
LOC Bank   Amount(2)     LOC Termination Date   LOC Draws Due
    (In millions)          
CitiBank N.A.
  $ 166     June 2014   June 2014
The Bank of Nova Scotia
    284     Beginning April 2011   Multiple dates(3)
The Royal Bank of Scotland
    131     June 2012   6 months
Wachovia Bank
    152     March 2014   March 2014
Barclays Bank(1)
    528     Beginning December 2010   30 days
PNC Bank
    70     Beginning November 2010   180 days
 
             
Total
  $ 1,331          
 
             
     
(1)  
Supported by 18 participating banks, with no one bank having more than 14% of the total commitment.
 
(2)  
Includes approximately $13 million of applicable interest coverage.
 
(3)  
Shorter of 6 months or LOC termination date ($155 million) and shorter of one year or LOC termination date ($129 million).
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, FES completed the refinancing and remarketing of six series of PCRBs totaling $313 million. These PCRBs were converted from a variable interest rate to a fixed long term interest rate of 3.375% per annum and are subject to mandatory purchase on July 1, 2015. The LOCs for the refinanced series of PCRBs totaling $208 million terminated as of October 1, 2010. The LOCs for the remarketed series of PCRBs totaling $108 million will terminate on November 1, 2010.
Long-Term Debt Capacity
As of September 30, 2010, the Ohio Companies and Penn had the aggregate capability to issue approximately $2.5 billion of additional FMBs on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMBs by the Ohio Companies is also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMBs) supporting pollution control notes or similar obligations, or as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE and CEI to incur additional secured debt not otherwise permitted by a specified exception of up to $116 million and $25 million, respectively, as of September 30, 2010. As a result of the indenture provisions, TE cannot incur any additional secured debt. Met-Ed and Penelec had the capability to issue secured debt of approximately $380 million and $358 million, respectively, under provisions of their senior note indentures as of September 30, 2010.
Based upon FGCO’s FMB indenture, net earnings and available bondable property additions as of September 30, 2010, FGCO had the capability to issue $1.9 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 of additional FMBs as of September 30, 2010.
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’s and its subsidiaries’ credit ratings by one notch, while maintaining its stable outlook. Moody’s and Fitch affirmed the ratings and stable outlook of FirstEnergy and its subsidiaries on February 11, 2010. On September 28, 2010, S&P issued a report reaffirming the ratings and stable outlook of FirstEnergy and its subsidiaries. The following table displays FirstEnergy’s, FES’ and the Utilities’ securities ratings as of September 30, 2010.
                         
    Senior Secured   Senior Unsecured
Issuer   S&P   Moody’s   Fitch   S&P   Moody’s   Fitch
FirstEnergy Corp.
        BB+   Baa3   BBB
FirstEnergy Solutions
        BBB-   Baa2   BBB
Ohio Edison
  BBB   A3   BBB+   BBB-   Baa2   BBB
Pennsylvania Power
  BBB+   A3   BBB+      
Cleveland Electric Illuminating
  BBB   Baa1   BBB   BBB-   Baa3   BBB-
Toledo Edison
  BBB   Baa1   BBB      
Jersey Central Power & Light
        BBB-   Baa2   BBB+
Metropolitan Edison
  BBB   A3   BBB+   BBB-   Baa2   BBB
Pennsylvania Electric
  BBB   A3   BBB+   BBB-   Baa2   BBB
ATSI
        BBB-   Baa1  
Changes in Cash Position
As of September 30, 2010, FirstEnergy had $632 million of cash and cash equivalents compared to $874 million as of December 31, 2009. As of September 30, 2010 and December 31, 2009, FirstEnergy had approximately $14 million and $12 million, respectively, of restricted cash included in other current assets on the Consolidated Balance Sheet.
During the first nine months of 2010, FirstEnergy received $730 million of cash dividends from its subsidiaries and paid $503 million in cash dividends to common 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 increased by $609 million during the first nine months of 2010 compared to the comparable period in 2009, as summarized in the following table:
                         
    Nine Months        
    Ended September 30     Increase  
Operating Cash Flows   2010     2009     (Decrease)  
    (In millions)  
Net income
  $ 580     $ 754     $ (174 )
Non-cash charges and other adjustments
    1,648       1,755       (107 )
Pension trust contribution
          (500 )     500  
Working Capital and other
    (155 )     (545 )     390  
 
                 
 
  $ 2,073     $ 1,464     $ 609  
 
                 

 

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The decrease 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 in deferred income taxes and investment tax credits of ($162 million). The decrease in non-cash charges and other adjustments was partially offset by impairment 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.
The change in 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 second and third quarters of 2010, changes in investment securities of $133 million, a decrease in prepaid assets of $345 million and a $250 million increase in accounts receivable.
Cash Flows From Financing Activities
In the first nine months of 2010, cash used for financing activities was $870 million compared to cash provided from financing activities of $617 million in the first nine 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. The following table summarizes security issuances (net of any discounts) and redemptions:
                 
    Nine Months  
    Ended September 30  
Securities Issued or Redeemed   2010     2009  
    (In millions)  
New Issues
               
First mortgage bonds
          398  
Pollution control notes
    250       859  
Senior secured notes
          297  
Unsecured Notes
    1       2,597  
 
           
 
  $ 251     $ 4,151  
 
           
 
               
Redemptions
               
First mortgage bonds
    7        
Pollution control notes
    251       687  
Senior secured notes
    63       54  
Unsecured notes
    101       1,472  
 
           
 
  $ 422     $ 2,213  
 
           
 
               
Short-term borrowings, net
  $ (171 )   $ (764 )
 
           
Cash Flows From Investing Activities
Net cash flows used in investing activities resulted primarily from property additions. Additions for the energy delivery services segment primarily represent expenditures related to transmission and distribution facilities. Capital spending by the competitive energy services segment is principally generation-related. The following table summarizes investing activities for the first nine months of 2010 and 2009 by business segment:
                                 
Summary of Cash Flows   Property                    
Provided from (Used for) Investing Activities   Additions     Investments     Other     Total  
            (In millions)          
Sources (Uses)
                               
Nine Months Ended September 30, 2010
                               
Energy delivery services
  $ (546 )   $ 82     $ 11     $ (453 )
Competitive energy services
    (860 )     (26 )     (53 )     (939 )
Other
    (18 )     (3 )     34       13  
Inter-Segment reconciling items
    (43 )     (23 )           (66 )
 
                       
Total
  $ (1,467 )   $ 30     $ (8 )   $ (1,445 )
 
                       
 
                               
Nine Months Ended September 30, 2009
                               
Energy delivery services
  $ (524 )   $ (121 )   $ (35 )   $ (680 )
Competitive energy services
    (893 )     (6 )     (21 )     (920 )
Other
    (133 )             (11 )     (144 )
Inter-Segment reconciling items
    (25 )     (25 )     6       (44 )
 
                       
Total
  $ (1,575 )   $ (152 )   $ (61 )   $ (1,788 )
 
                       

 

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Net cash used for investing activities in the first nine months of 2010 decreased by $343 million compared to the first nine months of 2009. The decrease was principally due to a $108 million decrease in property additions (principally lower AQC system expenditures) and an increase in cash proceeds from the sale of assets of $98 million, partially offset by $110 million spent by FES in the customer acquisition process.
During the remaining quarter of 2010, capital requirements for property additions and capital leases are expected to be approximately $410 million, including approximately $32 million for nuclear fuel. These cash requirements are expected to be satisfied from a combination of internal cash and short-term credit arrangements.
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.
As of September 30, 2010, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $3.8 billion, as summarized below:
         
    Maximum  
Guarantees and Other Assurances   Exposure  
    (In millions)  
FirstEnergy Guarantees on Behalf of its Subsidiaries
       
Energy and Energy-Related Contracts(1)
  $ 300  
LOC (long-term debt) —Interest coverage(2)
    6  
FirstEnergy guarantee of OVEC obligations
    300  
Other(3)
    226  
 
     
 
    832  
 
     
 
       
Subsidiaries’ Guarantees
       
Energy and Energy-Related Contracts
    54  
LOC (long-term debt) —Interest coverage(2)
    4  
FES’ guarantee of NGC’s nuclear property insurance
    70  
FES’ guarantee of FGCO’s sale and leaseback obligations
    2,413  
Other
    2  
 
     
 
    2,543  
 
     
 
       
Surety Bonds
    84  
LOC (long-term debt) — Interest coverage(2)
    3  
LOC (non-debt)(4)(5)
    380  
 
     
 
    467  
 
     
Total Guarantees and Other Assurances
  $ 3,842  
 
     
     
(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 million for railcar leases.
 
(4)  
Includes $201 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facility.
 
(5)  
Includes approximately $135 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $44 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, FirstEnergy’s maximum exposure under these collateral provisions was $419 million, as shown below:
                         
Collateral Provisions   FES     Utilities     Total  
            (In millions)          
Credit rating downgrade to below investment grade (1)
  $ 306     $ 68     $ 374  
Material adverse event (2)
    45             45  
 
                 
Total
  $ 351     $ 68     $ 419  
 
                 
     
(1)  
Includes $85 million and $57 million that is also considered an acceleration of payment or funding obligation at FES and the Utilities, respectively.
 
(2)  
Includes $33 million that is also considered an acceleration of payment or funding obligation at FES.
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 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.
Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $84 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.
In addition to guarantees and surety bonds, FES’ contracts, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions which require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ power portfolio as of September 30, 2010, and forward prices as of that date, FES has posted collateral of $244 million. 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. Depending on the volume of forward contracts and future price movements, FES could be required to post higher amounts for margining.
In connection with FES’ obligations to post and maintain collateral under the two-year PSA entered into by FES and the Ohio Companies following the CBP auction on May 13-14, 2009, NGC entered into a Surplus Margin Guaranty in 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.
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. 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.

 

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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.
MARKET RISK INFORMATION
FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.
Commodity Price Risk
FirstEnergy is exposed to financial and market risks resulting from the fluctuation of interest rates and commodity prices associated with electricity, energy transmission, natural gas, coal, nuclear fuel and emission allowances. To manage the volatility relating to these exposures, FirstEnergy uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes.
The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, FirstEnergy relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FirstEnergy uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making (see Note 5 to the consolidated financial statements). Sources of information for the valuation of commodity derivative contracts as of September 30, 2010 are summarized by year in the following table:
                                                         
Source of Information-                                          
Fair Value by Contract Year   2010     2011     2012     2013     2014     Thereafter     Total  
                    (In millions)                  
Prices actively quoted(1)
  $ (2 )   $     $     $     $     $     $ (2 )
Other external sources(2)
    (328 )     (369 )     (164 )     (53 )     7       (10 )     (917 )
Prices based on models
                            (9 )     141       132  
 
                                         
Total(3)
  $ (330 )   $ (369 )   $ (164 )   $ (53 )   $ (2 )   $ 131     $ (787 )
 
                                         
     
(1)  
Represents exchange traded New York Mercantile Exchange futures and options.
 
(2)  
Primarily represents contracts based on broker and IntercontinentalExchange quotes.
 
(3)  
Includes $629 million in non-hedge commodity derivative contracts that are primarily related to NUG contracts. NUG contracts are subject to regulatory accounting and do not impact earnings.
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, an adverse 10% change in commodity prices would decrease net income by approximately $6 million ($4 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 and non-qualified pension plans that cover certain employees. The plan provides defined benefits based on years of service and compensation levels. FirstEnergy also provides health care benefits (which include certain employee contributions, deductibles and co-payments) upon retirement to employees hired prior to January 1, 2005, their dependents, and under certain circumstances, their survivors. The benefit plan assets and obligations are remeasured annually using a December 31 measurement date or as significant triggering events occur. As of September 30, 2010, approximately 44% of the pension plan assets are invested in equity securities and 56% are invested in fixed income securities. The plan is 81% funded on an accumulated benefit obligation basis as of September 30, 2010. A decline in the value of FirstEnergy’s pension plan assets could result in additional funding requirements. FirstEnergy currently estimates that additional cash contributions will be required beginning in 2012.

 

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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, approximately 15% of the funds were invested in equity securities and 85% were invested in fixed income securities, with limitations related to concentration and investment grade ratings. The equity securities are carried at their market value of approximately $305 million as of September 30, 2010. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $31 million reduction in fair value as of September 30, 2010. The decommissioning trusts of JCP&L and the Pennsylvania Companies are subject to regulatory accounting, with unrealized gains and losses recorded as regulatory assets or liabilities, since the difference between investments held in trust and the decommissioning liabilities will be recovered from or refunded to customers. NGC, OE and TE recognize in earnings the unrealized losses on available-for-sale securities held in their nuclear decommissioning trusts as other-than-temporary impairments. A decline in the value of FirstEnergy’s nuclear decommissioning trusts could result in additional funding requirements. During 2010, $4 million was contributed to the OE and TE nuclear decommissioning trusts to comply with requirements under certain sale-leaseback transactions in which OE and TE continue as lessees, and $4 million was contributed to the JCP&L and Pennsylvania nuclear decommissioning trusts to comply with regulatory requirements. FirstEnergy continues to evaluate the status of its funding obligations for the decommissioning 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.
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, the largest credit concentration was with J.P. Morgan Chase & Co., which is currently rated investment grade, representing 9.42% of FirstEnergy’s total approved credit risk.
OUTLOOK
Reliability Initiatives
Federally-enforceable mandatory reliability standards apply to the bulk power system and impose certain operating, record-keeping and reporting requirements on the Utilities and ATSI. The NERC has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including ReliabilityFirst Corporation. All of FirstEnergy’s facilities are located within the ReliabilityFirst region. FirstEnergy actively participates in the NERC and ReliabilityFirst stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by the ReliabilityFirst Corporation.
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 arise in the normal course of operations. FirstEnergy also believes that the NERC, ReliabilityFirst and the FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with new or amended standards cannot be determined at this time; however, 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 a vegetation encroachment event on a Met-Ed 230 kV line to ReliabilityFirst. 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, ReliabilityFirst issued a Notice of Enforcement to investigate the incident. FirstEnergy submitted a data response to ReliabilityFirst on September 27, 2010. At this time, FirstEnergy is unable to predict the outcome of this investigation.
Ohio
The Ohio Companies operate under an Amended ESP, which expires on May 31, 2011, and 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.
On March 23, 2010, the Ohio Companies filed an application for a new ESP. 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 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 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 that retail customers of the Ohio Companies will not pay certain costs related to the companies’ integration into PJM, 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 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.
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.

 

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On December 15, 2009, the Ohio Companies filed the required three year portfolio plan seeking approval for the programs they intend to implement to meet the energy efficiency and peak demand reduction requirements for the 2010-2012 period. On March 8, 2010, the Ohio Companies filed their 2009 Status Update Report with the PUCO in which they indicated compliance with the 2009 statutory energy efficiency and peak demand benchmarks as those benchmarks were amended as described above. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers. The Ohio Companies’ three year portfolio plan is still awaiting decision from the PUCO. The plan has yet to be approved by the PUCO, which is delaying the launch of the programs described in the plan. Without such approval, the Ohio Companies’ compliance with 2010 benchmarks is jeopardized and if not approved soon may require the Ohio Companies to seek an amendment to their annual benchmark requirements for 2010. Failure to comply with the benchmarks or to obtain such an amendment may subject the Companies to an assessment by the PUCO of a forfeiture.
Additionally under SB221, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they 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. 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 CEI filed an application with the PUCO to establish a new credit for all-electric customers. On March 3, 2010, the PUCO ordered that rates for the affected customers be set at a level that will provide bill impacts commensurate with charges in place on December 31, 2008 and authorized the Ohio Companies to defer incurred costs equivalent to the difference between what the affected customers would have paid under previously existing rates and what they pay with the new credit in place. Tariffs implementing this new credit went into effect on March 17, 2010. On April 15, 2010, the PUCO issued a Second Entry on Rehearing that expanded the group of customers to which the new credit would apply and authorized deferral for the associated additional amounts. The PUCO also stated that 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 rehearing of 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.
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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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 denies the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, and directs Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructs Met-Ed and Penelec to work with the various intervening parties to file a 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 outcome 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.
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 NUGC rates and 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 comments in the proceeding in November 2007. A schedule for further NJBPU proceedings has not yet been set. On March 13, 2009, JCP&L filed its annual SBC Petition with the NJBPU that includes a request for a reduction in the level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009 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.
FERC Matters
PJM Transmission Rate
On 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 on 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 the reply comments. 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 their costs. Numerous parties filed responsive comments or studies on May 28, 2010 and reply comments on June 28, 2010. FirstEnergy and a number of other utilities, industrial customers and state commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. Certain eastern utilities and their state commissions supported continued socialization of these costs on a load ratio share basis. FERC is expected to act before the end of the year.

 

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RTO Consolidation
On December 17, 2009, FERC issued an order approving, subject to certain future compliance filings, ATSI’s move to PJM. This move, which is expected to be effective on June 1, 2011, allows 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 requirements 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. Execution 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 completion of these steps secured the capacity necessary for the ATSI footprint to meet PJM’s capacity requirements.
On September 4, 2009, the PUCO opened a case 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 of the move into PJM, and certain of these matters remain outstanding and will 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.
MISO Multi-Value Project Rule Proposal
On July 15, 2010, MISO and certain MISO transmission owners jointly filed with FERC their proposed cost allocation methodology for new transmission projects. The new transmission projects—described as Multi-Value Projects (MVPs)—are a class of MTEP projects. The MISO proposes 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 expects that its 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 has requested that FERC rule on its MVP proposal by December, but has asked for an effective date for its proposal of July 16, 2011. On August 19, 2010, MISO’s Board approved the first MVP 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’s estimated allocations of the costs for the Michigan Thumb Project, where approximately $16 million in annual revenue requirements were allocated to the ATSI zone.
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). 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. Numerous other parties filed pleadings on MISO’s MVP proposal. FirstEnergy is unable to predict the outcome of this matter.
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 SO2 and NOX 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 NOX 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, PennFuture filed a citizen suit under the CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations, in the U.S. District Court for the Western District of Pennsylvania. In July 2008, three additional complaints were filed against FGCO 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 those three complaints.
The states of New Jersey and Connecticut filed CAA citizen suits in 2007 alleging NSR violations at the Portland Generation Station against RRI Energy, Inc. (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.
In January 2009, the EPA issued a NOV to Reliant 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. alleging that “modifications” at the Homer City Power Station occurred since 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 identical allegations as 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 required 60 days prior to filing a citizen suit under the CAA. 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.
National Ambient Air Quality Standards
The EPA’s CAIR requires reductions of NOX and SO2 emissions in two phases (2009/2010 and 2015), ultimately capping SO2 emissions in affected states to 2.5 million tons annually and NOX emissions to 1.3 million tons annually. In 2008, the U.S. Court of Appeals for the District of Columbia vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” In December 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s opinion. The Court ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOX SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the “8-hour” ozone NAAQS. In July 2010, the EPA proposed the Clean Air Transport Rule (CATR) to replace CAIR, which remains in effect until the EPA finalizes CATR. CATR requires reductions of NOX and SO2 emissions in two phases (2012 and 2014), ultimately capping SO2 emissions in affected states to 2.6 million tons annually and NOX emissions to 1.3 million tons annually. The EPA proposed a preferred regulatory approach that allows trading of NOX and SO2 emission allowances between power plants located in the same state 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 NOX and SO2 emission allowances and the second eliminates trading of NOX and SO2 emission allowances in its entirety. Depending on the actions taken by the EPA with respect to CATR, the proposed MACT regulations discussed below and any future regulations that are ultimately implemented, FGCO’s future cost of compliance 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, and to finalize the regulations by November 16, 2011. Depending on the action taken by the EPA and on how any future regulations are ultimately implemented, FGCO’s future cost of compliance with MACT regulations may be substantial and changes to FGCO’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, on June 26, 2009. The Senate continues to consider a number of measures to regulate GHG emissions. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuring that 10% of electricity used in the United States comes from renewable sources by 2012, increasing to 25% by 2025, and implementing an economy-wide cap-and-trade program to reduce GHG emissions by 80% by 2050. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states, led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.
In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that will require FirstEnergy to measure GHG emissions commencing in 2010 and submit reports commencing in 2011. In December 2009, the EPA released 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 until July 1, 2011 that emissions applicability threshold will only apply if PSD is triggered by non-carbon dioxide pollutants.
At the international level, the Kyoto Protocol, signed by the U.S. in 1998 but never submitted for ratification by the U.S. Senate, was intended to address global warming by reducing the amount of 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 which recognized the scientific view that the increase in global temperature should be below two degrees Celsius; include 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 establish the “Copenhagen Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. Once they have become a party to the Copenhagen Accord, developed economies, such as the European Union, Japan, Russia and the United States, would commit to quantified economy-wide emissions 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, 2009, the U.S. Court of Appeals for the Second Circuit and on October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit reversed and remanded lower court decisions that had dismissed complaints alleging damage from GHG emissions on jurisdictional grounds. However, a subsequent ruling from the U.S. Court of Appeals for the Fifth Circuit reinstated the lower court dismissal of a complaint alleging damage from GHG emissions. These cases involve common law tort claims, including public and private nuisance, alleging that GHG emissions contribute to global warming and result in property damages. While FirstEnergy is 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 regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy’s plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to FirstEnergy’s operations.
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. On 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. The EPA is developing a new regulation under Section 316(b) of the Clean Water Act consistent with the opinions of the Supreme Court and the Court of Appeals which have created significant uncertainty about the specific nature, scope and timing of the final performance standard. FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore power plant’s water intake channel to divert fish away from the plant’s water intake system. On March 15, 2010, the EPA issued a draft permit for the Bay Shore power plant requiring installation of reverse louvers in its entire water intake channel by December 31, 2014. Depending on the results of such studies and the EPA’s further rulemaking and any final action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.
In June 2008, the U.S. Attorney’s Office in Cleveland, Ohio advised FGCO that it is considering prosecution under the Clean Water Act and the Migratory Bird Treaty Act for three petroleum spills at the Edgewater, Lakeshore and Bay Shore plants which occurred on November 1, 2005, January 26, 2007 and February 27, 2007. FGCO is unable to predict the outcome of this matter.
Regulation of Waste Disposal
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.
On December 30, 2009, in an advanced notice of public rulemaking, the EPA said that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. On May 4, 2010, the EPA proposed two options for additional regulation 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’s future cost of compliance with any coal combustion residuals regulations which may be promulgated could be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the EPA or the states.

 

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The Utilities have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the consolidated balance sheet as of September 30, 2010, based on estimates of the total costs of cleanup, the Utilities’ proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $105 million (JCP&L — $76 million, TE — $1 million, CEI — $1 million, FGCO — $1 million and FirstEnergy — $26 million) have been accrued through September 30, 2010. Included in the total are accrued liabilities of approximately $67 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.
Other Legal Proceedings
Power Outages and Related Litigation
In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L’s territory. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages due to the outages. After various motions, rulings and appeals, the Plaintiffs’ claims for consumer fraud, common law fraud, negligent misrepresentation, strict product liability and punitive damages were dismissed, leaving only the negligence and breach of contract causes of actions. 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 for the Court’s decision.
Litigation Relating to 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 Energy and its directors and certain officers, referred 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. 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 breached their fiduciary duties by approving the merger agreement, and that Allegheny Energy, FirstEnergy and Merger Sub aided and abetted in these alleged breaches of fiduciary duty. The complaints seek, among other things, jury trials, money damages and injunctive relief. 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.

 

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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.
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, FirstEnergy had approximately $2.0 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. FirstEnergy provides an additional $15 million parental guarantee associated with the funding of decommissioning costs for these units.
Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.
On 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. On 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.
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 11 of the Combined Notes to the Consolidated Financial Statements (Unaudited) for discussion of new accounting pronouncements.

 

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FIRSTENERGY SOLUTIONS CORP.
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
FES is a wholly owned subsidiary of FirstEnergy. FES provides energy-related products and services, and through its subsidiaries, FGCO and NGC, owns or leases and operates and maintains FirstEnergy’s fossil and hydroelectric generation facilities, and owns FirstEnergy’s nuclear generation facilities, respectively. FENOC, a wholly owned subsidiary of FirstEnergy, operates and maintains the nuclear generating facilities.
FES’ revenues 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 concentrated in Ohio, Pennsylvania, Illinois, Maryland, Michigan and New Jersey.
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 income decreased by $491 million in the first nine months of 2010, compared to the same period of 2009. 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 electricity 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.
Revenues
Excluding the impact of the 2009 gain on the OVEC sale, total revenues increased $836 million in the first nine months of 2010, compared to the same period of 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 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 )
Other Wholesale
    322       503       (181 )
Transmission
    58       57       1  
RECs
    67             67  
Sale of OVEC participation interest
          252       (252 )
Other
    84       85       (1 )
 
                 
Total Revenues
  $ 4,256     $ 3,672     $ 584  
 
                 
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 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. In addition, sales to residential and small commercial customers were bolstered by weather in the delivery area that was 69% warmer than in 2009.

 

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The decrease in POLR revenues of $458 million was due to lower sales volumes to the Ohio Companies and lower unit prices, partially offset by increased sales volumes and higher unit prices to the Pennsylvania Companies. The lower sales volumes and unit prices to the Ohio Companies in 2010 reflected the results of the May 2009 power procurement process. The increased revenues 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 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 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.
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.
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, compared with the same period of 2009.

 

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The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first nine months of 2010, from the same period last year:
         
    Increase  
Source of Change in Fuel and Purchased Power   (Decrease)  
    (In millions)  
Fossil Fuel:
       
Change due to increased unit costs
  $ 30  
Change due to volume consumed
    135  
 
     
 
    165  
 
     
Nuclear Fuel:
       
Change due to increased unit costs
    23  
Change due to volume consumed
    3  
 
     
 
    26  
 
     
Non-affiliated Purchased Power:
       
Power contract mark-to-market adjustment
    43  
Change due to decreased unit costs
    (84 )
Change due to volume purchased
    650  
 
     
 
    609  
 
     
Affiliated Purchased Power:
       
Change due to increased unit costs
    81  
Change due to volume purchased
    15  
 
     
 
    96  
 
     
Net Increase in Fuel and Purchased Power Costs
  $ 896  
 
     
Fossil fuel costs increased $165 million in the first nine months of 2010, compared to the same period of 2009, as a result of higher generation volumes consumed combined with increased 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 million primarily due to the replacement of nuclear fuel at higher unit costs following the refueling outages that occurred in 2009.
Non-affiliated purchased power costs increased $609 million due primarily to higher volumes purchased and a power contract mark-to-market adjustment, partially offset by lower unit costs. The increase in volume primarily relates to the assumption of a 1,300 MW third party contract from Met-Ed and Penelec. Affiliated purchased power increased $96 million primarily due to higher unit costs combined with higher volumes purchased from affiliated companies.
Other operating expenses increased $25 million in the first nine months of 2010, compared to the same period of 2009, primarily due to increased transmission expenses ($36 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 volumes and increased uncollectible customer accounts and agent fees ($22 million) associated with the growth in direct and government aggregation sales, partially offset by lower nuclear ($39 million) 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 nine month of 2010 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.
General taxes increased $5 million due to sales taxes associated with increased revenues.
Other Expense
Total other expense increased $128 million in the first nine months of 2010, compared to the same period of 2009, primarily due to a decrease in nuclear decommissioning trust investment income ($94 million) combined with an increase in interest expense (net of capitalized interest). Interest expense increased primarily due to new long-term debt issued combined with the restructuring of existing PCRBs.

 

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OHIO EDISON COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
OE is a wholly owned electric utility subsidiary of FirstEnergy. OE 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 increased by $40 million in the first nine months of 2010, compared to the same period of 2009. The increase primarily resulted from lower purchased power costs and other operating costs, partially offset by lower revenues and investment income.
Revenues
Revenues decreased $589 million, or 29%, in the first nine months of 2010, compared with the same period in 2009, due primarily to a decrease in generation revenues.
Retail generation revenues decreased $584 million primarily due to a decrease in KWH sales in all customer classes. Lower KWH sales were primarily the result of a 42% increase in 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 nine 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.
Changes in retail generation KWH sales and revenues in the first nine months of 2010, compared to the same period in 2009, are summarized in the following tables:
         
Retail Generation KWH Sales   Decrease  
 
       
Residential
    (26.0 )%
Commercial
    (60.0 )%
Industrial
    (62.7 )%
 
     
Decrease in Retail Generation Sales
    (45.7 )%
 
     
         
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.

 

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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 Sales   Increase  
 
       
Residential
    6.3 %
Commercial
    2.1 %
Industrial
    10.6 %
 
     
Increase in Distribution Deliveries
    6.2 %
 
     
         
    Increase  
Distribution Revenues   (Decrease)  
    (In millions)  
Residential
  $ 27  
Commercial
    (9 )
Industrial
    (19 )
 
     
Net Decrease in Distribution Revenues
  $ (1 )
 
     
Expenses
Total expenses decreased $674 million in the first nine months of 2010, from the same period of 2009. The following table presents changes from the prior period by expense category:
         
    Increase  
Expenses - Changes   (Decrease)  
    (In millions)  
Purchased power costs
  $ (564 )
Other operating expenses
    (100 )
Amortization of regulatory assets, net
    (11 )
General taxes
    1  
 
     
Net Decrease in Expenses
  $ (674 )
 
     
Purchased power costs decreased in the first nine months of 2010, compared to the same period of 2009, primarily due to lower KWH purchases resulting from reduced requirements from increased customer shopping in the first nine months of 2010 and slightly lower unit costs. The decrease in other operating costs for the first nine months of 2010, 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 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 million in the first nine months of 2010, compared to the same period of 2009, primarily due to lower nuclear decommissioning trust investment income.

 

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THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI conducts business in northeastern Ohio, 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 increased by $93 million in the first nine months of 2010, compared to the same period of 2009. The increase in earnings was primarily due to the absence in 2010 of one-time regulatory charges recognized in 2009, and decreased purchased power and other operating costs, partially offset by decreased revenues and deferred regulatory assets.
Revenues
Revenues decreased $406 million, or 30%, in the first nine months of 2010, compared to the same period of 2009, due to decreased retail generation and distribution revenues.
Distribution revenues decreased $76 million in the first nine months of 2010, compared to the same period of 2009, due to lower average unit prices for all customer classes offset by increased KWH deliveries in all sectors. The lower average unit prices were the result of lower transition rates in 2010. Higher residential deliveries resulted from increased weather-related usage in the first nine months of 2010, reflecting a 73% increase in cooling degree days. Increased industrial deliveries were the result of an increase in KWH deliveries to major steel customers (168%) and automotive customers (12%), reflecting improving economic conditions.
Changes in distribution KWH deliveries and revenues in the first nine months of 2010, compared to the same period of 2009, are summarized in the following tables:
         
Distribution KWH Sales   Increase  
 
       
Residential
    7.3 %
Commercial
    2.4 %
Industrial
    14.4 %
 
     
Increase in Distribution Deliveries
    8.8 %
 
     
         
Distribution Revenues   Decrease  
    (In millions)  
Residential
  $  
Commercial
    (29 )
Industrial
    (47 )
 
     
Decrease in Distribution Revenues
  $ (76 )
 
     
Retail generation revenues decreased $321 million in the first nine months of 2010, compared to the same period of 2009, primarily due to lower KWH sales across all customer classes. Reduced KWH sales were primarily the result of increased 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 KWH deliveries resulting from the warmer weather conditions described above. Decreased volumes were partially offset by higher average unit prices in all customer classes. Retail generation prices increased in 2010 as a result of the CBP auction for the service period beginning June 1, 2009.

 

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Changes in retail generation sales and revenues in the first nine months of 2010, compared to the same period of 2009, are summarized in the following tables:
         
Retail Generation KWH Sales   Decrease  
 
       
Residential
    (51.7 )%
Commercial
    (69.4 )%
Industrial
    (47.4 )%
 
     
Decrease in Retail Generation Sales
    (54.2 )%
 
     
         
Retail Generation Revenues   Decrease  
    (In millions)  
Residential
  $ (78 )
Commercial
    (126 )
Industrial
    (117 )
 
     
Decrease in Retail Generation Revenues
  $ (321 )
 
     
Expenses
Total expenses decreased $561 million in the first nine months of 2010, compared to the same period of 2009. The following table presents the change from the prior period by expense category:
         
    Increase  
Expenses - Changes   (Decrease)  
    (In millions)  
Purchased power costs
  $ (441 )
Other operating costs
    (45 )
Amortization of regulatory assets, net
    (205 )
Deferral of new regulatory assets
    135  
General taxes
    (5 )
 
     
Net Decrease in Expenses
  $ (561 )
 
     
Purchased power costs decreased in the first nine months of 2010, primarily due to lower KWH sales requirements as discussed above. Other operating costs decreased due to lower transmission expenses (assumed by third party suppliers beginning June 1, 2009), labor and employee benefit expenses and the absence in 2010 of $12 million of costs incurred in the first nine months of 2009 associated with regulatory obligations for economic development and energy efficiency programs. Decreased amortization of regulatory assets was due primarily to the 2009 impairment of CEI’s Extended RTC regulatory asset of $216 million in accordance with the PUCO-approved ESP. A decrease in the deferral of new regulatory assets was primarily due to CEI’s contemporaneous recovery of purchased power costs in 2010. General taxes decreased in the first 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.

 

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THE TOLEDO EDISON COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
TE is a wholly owned electric utility subsidiary of FirstEnergy. TE conducts business in northwestern Ohio, providing regulated electric distribution services. TE also procures generation services for those customers electing to retain TE as their power supplier.
For additional information with respect to TE, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Earnings available to parent increased by $13 million in the first nine months of 2010, compared to the same period of 2009. The increase was primarily due to decreased net amortization of regulatory assets, purchased power and other operating costs, partially offset by an increase in interest expense and decreases in revenues and investment income.
Revenues
Revenues decreased $287 million, or 42%, in the first nine months of 2010, compared to the same period of 2009, primarily due to lower retail generation and distribution revenues, partially offset by an increase in wholesale generation revenues.
Distribution revenues decreased $22 million in the first nine months of 2010, compared to the same period of 2009, primarily due to lower unit prices, partially offset by increased KWH deliveries to all customer classes. Lower unit prices are primarily due to lower transmission rates. Higher KWH deliveries were influenced by weather-related usage in the first nine months of 2010, reflecting an 84% increase in cooling degree days in TE’s service territory. Increased industrial deliveries were the result of an increase in KWH deliveries to major automotive customers (29%) and steel customers (27%), reflecting improving economic conditions.
Changes in distribution KWH deliveries and revenues in the first nine months of 2010, compared to the same period of 2009, are summarized in the following tables:
         
Distribution KWH Sales   Increase  
 
       
Residential
    9.8 %
Commercial
    2.2 %
Industrial
    15.5 %
 
     
Increase in Distribution Deliveries
    10.3 %
 
     
         
    Increase  
Distribution Revenues   (Decrease)  
    (In millions)  
Residential
  $ 2  
Commercial
    (7 )
Industrial
    (17 )
 
     
Net Decrease in Distribution Revenues
  $ (22 )
 
     
Retail generation revenues decreased $282 million in the first nine months of 2010, compared to the same period of 2009, primarily due to lower KWH sales across all customer classes and lower unit prices to industrial customers. Lower KWH sales to all customer classes were primarily the result of a 59% increase in 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 from the CBP auction, effective June 1, 2009.

 

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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:
         
Retail Generation KWH Sales   Decrease  
 
       
Residential
    (45.1 )%
Commercial
    (72.5 )%
Industrial
    (59.4 )%
 
     
Decrease in Retail Generation Sales
    (59.0 )%
 
     
         
Retail Generation Revenues   Decrease  
    (In millions)  
Residential
  $ (57 )
Commercial
    (104 )
Industrial
    (121 )
 
     
Decrease in Retail Generation Revenues
  $ (282 )
 
     
Wholesale revenues increased $14 million in the first nine months of 2010, compared to the same period of 2009, primarily due to higher revenues from sales to NGC from TE’s leasehold interest in Beaver Valley Unit 2.
Expenses
Total expenses decreased $328 million in the first nine months of 2010, compared to the same period of 2009. The following table presents changes from the prior period by expense category:
         
    Increase  
Expenses - Changes   (Decrease)  
    (In millions)  
Purchased power costs
  $ (263 )
Other operating expenses
    (31 )
Provision for depreciation
    1  
Amortization (deferral) of regulatory assets, net
    (35 )
 
     
Net Decrease in Expenses
  $ (328 )
 
     
Purchased power costs decreased in the first nine months of 2010, compared to the same period of 2009, due to lower volume as a result of decreased KWH sales requirements. Other operating costs decreased primarily due to reduced transmission expense (assumed by third party suppliers beginning June 1, 2009), lower costs associated with regulatory obligations for economic development and energy efficiency programs and decreased labor expenses. The amortization of regulatory assets decreased primarily due to PUCO-approved cost deferrals and lower MISO transmission cost amortization in the first nine months of 2010, 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.

 

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JERSEY CENTRAL POWER & LIGHT COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
JCP&L is a wholly owned, electric utility subsidiary of FirstEnergy. JCP&L conducts business in New Jersey, providing regulated electric transmission and distribution services. JCP&L also procures generation services for franchise customers electing to retain JCP&L as their power supplier. JCP&L procures electric supply to serve its BGS customers through a statewide auction process approved by the NJBPU.
For additional information with respect to JCP&L, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Net income increased by $34 million in the first nine months of 2010, compared to the same period of 2009. The increase was primarily due to higher revenues, lower purchased power costs and decreased net amortization of regulatory assets, partially offset by increased other operating costs.
Revenues
In the first nine months of 2010, revenues increased $43 million, or 2%, compared to the same period of 2009. The increase in revenues is primarily due to higher distribution, wholesale generation and other revenues, partially offset by a decrease in retail generation revenues.
Distribution revenues increased $63 million in the first nine months of 2010, compared to the same period of 2009, due to higher KWH deliveries in all customer classes. Increased usage was due to warmer weather and improved economic conditions in JCP&L’s service territory. Decreased composite unit prices in the commercial and industrial classes partially offset the increased volume.
Changes in distribution KWH deliveries and revenues in the first nine months of 2010 compared to the same period of 2009 are summarized in the following tables:
         
Distribution KWH Sales   Increase  
 
       
Residential
    10.6 %
Commercial
    2.9 %
Industrial
    3.0 %
 
     
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 Generation KWH Sales   (Decrease)  
 
       
Residential
    10.1 %
Commercial
    (27.7 )%
Industrial
    (21.4 )%
 
     
Net Decrease in Retail Generation Sales
    (5.0 )%
 
     
         
    Increase  
Retail Generation Revenues   (Decrease)  
    (In millions)  
Residential
  $ 81  
Commercial
    (127 )
Industrial
    (8 )
 
     
Net Decrease in Retail Generation Revenues
  $ (54 )
 
     
Wholesale generation revenues increased $22 million in the first nine months of 2010, compared to the same period of 2009, due primarily to higher wholesale energy prices.
Other revenues increased $8 million in the first nine months of 2010, compared to the same period of 2009, primarily due to an increase in transition bond revenues as a result of higher KWH deliveries in all customer classes.
Expenses
Total expenses decreased $18 million in the first nine months of 2010, compared to the same period of 2009. The following table presents changes from the prior period by expense category:
         
    Increase  
Expenses - Changes   (Decrease)  
    (In millions)  
Purchased power costs
  $ (33 )
Other operating costs
    19  
Provision for depreciation
    5  
Amortization of regulatory assets, net
    (12 )
General taxes
    3  
 
     
Net Decrease in Expenses
  $ (18 )
 
     
Purchased power costs decreased in the first nine months of 2010 primarily due to the lower retail generation KWH sales requirements. Other operating costs increased in the first nine months of 2010 primarily due to major storm clean up 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. The amortization of regulatory assets decreased in the first nine months of 2010 primarily due to the deferral of storm costs.

 

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METROPOLITAN EDISON COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
Met-Ed is a wholly owned electric utility subsidiary of FirstEnergy. Met-Ed 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. Met-Ed has a wholesale power sales agreement with FES, to supply all of its energy requirements at fixed prices through the end of 2010.
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 and New Accounting Standards and Interpretations.
Results of Operations
Net income increased by $6 million in the first nine months of 2010, compared to the same period of 2009. The increase was primarily due to increased revenues and decreased amortization of net regulatory assets, partially offset by increased purchased power and other operating expenses.
Revenues
Revenue increased $147 million, or 12%, in the first nine months of 2010 compared to the same period of 2009, reflecting higher distribution and generation revenues, partially offset by a decrease in transmission revenues.
Distribution revenues increased $82 million in the first nine months of 2010, compared to the same period of 2009, primarily due to higher rates resulting from the annual update to Met-Ed’s TSC rider effective June 1, 2010, partially offset by lower CTC rates for the residential class. 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% increase in cooling degree days in the first nine months of 2010, partially offset by an 11% decrease in heating degree days for the same period.
Changes in distribution KWH deliveries and revenues in the first nine months of 2010, compared to the same period of 2009, are summarized in the following tables:
         
Distribution KWH Deliveries   Increase  
 
       
Residential
    5.0 %
Commercial
    4.4 %
Industrial
    4.0 %
 
     
Increase in Distribution Deliveries
    4.6 %
 
     
         
Distribution Revenues   Increase  
    (In millions)  
Residential
  $ 40  
Commercial
    27  
Industrial
    15  
 
     
Increase in Distribution Revenues
  $ 82  
 
     
Retail generation revenues increased $36 million in the first nine months of 2010, compared to the same period of 2009, due to higher composite unit prices in the residential and commercial customer classes and higher KWH sales to all customer classes. The higher unit prices were primarily due to an increase in the generation rate, effective January 1, 2010. Higher KWH sales to residential and commercial customers increased primarily due to weather-related usage described above. Increased customer shopping in the commercial and industrial classes partially offset the higher KWH sales in these classes.

 

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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:
         
Retail Generation KWH Sales   Increase  
 
       
Residential
    5.0 %
Commercial
    2.8 %
Industrial
    1.1 %
 
     
Increase in Retail Generation Sales
    3.3 %
 
     
         
Retail Generation Revenues   Increase  
    (In millions)  
Residential
  $ 30  
Commercial
    5  
Industrial
    1  
 
     
Increase in Retail Generation Revenues
  $ 36  
 
     
Wholesale revenues increased $42 million in the first nine months of 2010 compared to the same period of 2009, primarily reflecting higher PJM capacity prices.
Transmission revenues decreased $13 million in the first nine months of 2010 compared to the same period of 2009 primarily due to decreased Financial Transmission Rights 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 $130 million in the first nine months of 2010 compared to the same period of 2009. The following table presents changes from the prior year by expense category:
         
    Increase  
Expenses - Changes   (Decrease)  
    (In millions)  
Purchased power costs
  $ 78  
Other operating costs
    112  
Provision for depreciation
    1  
Amortization of regulatory assets, net
    (61 )
 
     
Net Increase in Expenses
  $ 130  
 
     
Purchased power costs increased $78 million in the first nine months of 2010 due to an increase in unit costs and increased KWH purchased to source increased generation sales requirements. Other operating costs increased $112 million in the first nine months of 2010 compared to the same period in 2009 primarily due to higher 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 million in the first nine months of 2010 primarily due to higher PJM deferrals resulting from increased transmission costs and reduced amortization from decreasing asset balances.
Other Expense
In the first nine months of 2010, interest income decreased $4 million due to reduced CTC stranded asset balances.

 

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PENNSYLVANIA ELECTRIC COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts business in northern and south central Pennsylvania, providing regulated transmission and distribution services. Penelec also procures generation services for those customers electing to retain Penelec as their power supplier. Penelec has a wholesale power sales agreement with FES, to supply all of its energy requirements at fixed prices through the end of 2010.
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 and New Accounting Standards and Interpretations.
Results of Operations
Net income increased by $1 million in the first nine months of 2010, compared to the same period of 2009. The increase was 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. The increase in revenue was primarily due to higher generation revenues, partially offset by lower distribution 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 in all customer classes, partially offset by an increase in the universal service and energy efficiency rates for the residential customer class and increased KWH sales in all customer classes.
Changes in distribution KWH deliveries and revenues in the first nine months of 2010, compared to the same period of 2009, are summarized in the following tables:
         
Distribution KWH Deliveries   Increase  
 
       
Residential
    4.6 %
Commercial
    4.6 %
Industrial
    6.3 %
 
     
Increase in Distribution Deliveries
    5.1 %
 
     
         
    Increase  
Distribution Revenues   (Decrease)  
    (In millions)  
Residential
  $ 19  
Commercial
    (12 )
Industrial
    (9 )
 
     
Net Decrease in Distribution Revenues
  $ (2 )
 
     
Retail generation revenues increased $66 million in the first nine months of 2010, compared to the same period of 2009, primarily due to higher unit prices and KWH sales in all customer classes. The higher unit prices were primarily due to an increase in the generation rate, 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.

 

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Changes in retail generation sales and revenues in the first nine months of 2010 compared to the same period of 2009 are summarized in the following tables:
         
Retail Generation KWH Sales   Increase  
 
       
Residential
    4.6 %
Commercial
    4.3 %
Industrial
    6.9 %
 
     
Increase in Retail Generation Sales
    5.1 %
 
     
         
Retail Generation Revenues   Increase  
    (In millions)  
Residential
  $ 17  
Commercial
    26  
Industrial
    23  
 
     
Increase in Retail Generation Revenues
  $ 66  
 
     
Wholesale generation revenues increased $39 million in the first nine months of 2010, compared to the same period of 2009, due primarily to higher PJM capacity prices.
Transmission revenues decreased by $13 million in the first nine months of 2010, compared to the same period of 2009, primarily due to lower Financial Transmission Rights revenue. Penelec defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.
Expenses
Total expenses increased by $71 million in the first nine months of 2010, as compared with the same period of 2009. The following table presents changes from the prior period 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  
 
     
Purchased power costs increased $111 million in the first nine months of 2010, compared to the same period of 2009, primarily due to an increase in unit costs and increased KWH purchased to source increased generation sales requirements. Other operating costs increased $27 million in the first nine months of 2010, primarily due to higher transmission congestion and transmission loss expenses (see reference to deferral accounting above). The amortization (deferral) of net regulatory assets decreased $66 million in the first nine months of 2010, primarily due to increased cost deferrals resulting from higher transmission expenses and decreased amortization of regulatory assets resulting from lower CTC revenues. General taxes decreased $2 million primarily due to 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. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Risk Information” in Item 2 above.
ITEM 4. CONTROLS AND PROCEDURES
(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES — FIRSTENERGY
FirstEnergy’s 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 CONTROLS
During the quarter ended September 30, 2010, there were no changes in FirstEnergy’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrant’s internal control over financial reporting.
ITEM 4T. CONTROLS AND PROCEDURES — FES, OE, CEI, TE, JCP&L, MET-ED AND PENELEC
(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
Each registrant’s management, with the participation of its chief executive officer and chief financial officer, have reviewed and evaluated the effectiveness of such 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, 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.
(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. LEGAL PROCEEDINGS
Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 9 and 10 of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
ITEM 1A. RISK FACTORS
FirstEnergy’s Annual Report on Form 10-K for the year ended December 31, 2009, includes a detailed discussion of its risk factors. There have been no material changes to these risk factors for the quarter ended September 30, 2010.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
(c) FirstEnergy
The table below includes information on a monthly basis regarding purchases made by FirstEnergy of its common stock during the third quarter of 2010.
                                 
    Period  
    July     August     September     Third Quarter  
Total Number of Shares Purchased(a)
    38,180       43,103       460,312       541,595  
Average Price Paid per Share
  $ 36.41     $ 37.28     $ 36.76     $ 36.78  
Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs
                       
Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
                       
     
(a)  
Share amounts reflect purchases on the open market to satisfy FirstEnergy’s obligations to deliver common stock under its 2007 Incentive Compensation Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan and Stock Investment Plan. In addition, such amounts reflect shares tendered by employees to pay the exercise price or withholding taxes upon exercise of stock options granted under the 2007 Incentive Compensation Plan and the Executive Deferred Compensation Plan.
ITEM 5. OTHER INFORMATION
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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The facility contains customary representations, warranties, covenants and events of defaults of the borrowers, the guarantors and the pledgors and the foregoing description of the facility is qualified in its entirety by reference to the copy of the credit agreement, including the forms of the guaranty and pledge agreement attached as exhibits thereto, included with this report as Exhibit 10.3.
ITEM 6. EXHIBITS
Exhibit Number
             
FirstEnergy          
 
      10.1    
Amended FirstEnergy Corp. Deferred Compensation Plan for Outside Directors, amended and restated as of September 21, 2010.
      10.2    
Amended FirstEnergy Corp. Executive Deferred Compensation Plan, amended and restated as of September 21, 2010.
      10.3    
Signal Peak Credit Agreement, including the forms of the guaranty and pledge agreement attached as exhibits thereto
      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, 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          
 
      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          
 
      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
           
 
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)
      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
           
 
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

 

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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, 2010
         
 
FIRSTENERGY CORP.
Registrant

FIRSTENERGY SOLUTIONS CORP.
Registrant

OHIO EDISON COMPANY
Registrant

THE CLEVELAND ELECTRIC
ILLUMINATING COMPANY
Registrant

THE TOLEDO EDISON COMPANY
Registrant

METROPOLITAN EDISON COMPANY
Registrant

PENNSYLVANIA ELECTRIC COMPANY
Registrant  
 
 
  /s/ Harvey L. Wagner    
  Harvey L. Wagner   
  Vice President, Controller
and Chief Accounting Officer 
 
         
 
JERSEY CENTRAL POWER & LIGHT COMPANY
Registrant
 
 
  /s/ K. Jon Taylor    
  K. Jon Taylor   
  Controller
(Principal Accounting Officer) 
 

 

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