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 JuneSeptember 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.34-1843785

(An Ohio Corporation)

76 South Main Street

Akron, OH 44308

Telephone (800)736-3402		 34-1843785
     
000-53742 FIRSTENERGY SOLUTIONS CORP.31-1560186

(An Ohio Corporation)

c/o FirstEnergy Corp.

76 South Main Street
Akron, OH 44308
Telephone (800)736-3402		 
Akron, OH 44308
Telephone (800)736-340231-1560186
     
1-2578 OHIO EDISON COMPANY
(An Ohio Corporation)		34-0437786

c/o FirstEnergy Corp.

76 South Main Street

Akron, OH 44308

Telephone (800)736-3402		 34-0437786
     
1-2323 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY34-0150020

(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 COMPANY34-4375005

(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 COMPANY21-0485010

(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 COMPANY23-0870160

(A Pennsylvania Corporation)

c/o FirstEnergy Corp.

76 South Main Street

Akron, OH 44308

Telephone (800)736-3402		 23-0870160
     
1-3522 PENNSYLVANIA ELECTRIC COMPANY25-0718085

(A Pennsylvania Corporation)

c/o FirstEnergy Corp.

76 South Main Street

Akron, OH 44308

Telephone (800)736-3402		 25-0718085
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
   
Yesþ Noo
 FirstEnergy Corp., FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
   
Yesþ Noo
 FirstEnergy Corp.
   
Yeso Noo
 FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company, and Pennsylvania Electric Company
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
   
Large Accelerated Filerþ
 FirstEnergy Corp.
   
Accelerated Filero
 N/A
   
Non-accelerated Filer (Do not check if a smaller reporting company)þ
 FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company
   
Smaller Reporting Companyo
 N/A
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
   
Yeso Noþ
 FirstEnergy Corp., FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:
     
  OUTSTANDING 
CLASS AS OF JULY 31,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.
 
 

 

 

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 internetInternet 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 theFirstEnergy’s Internet web site and recognize theFirstEnergy’s Internet web site is aas channel of distribution to reach public investors and as a means of disclosing material non-public information for complying with disclosure obligations under SEC Regulation FD. Information contained on FirstEnergy’s Internet web site shall not be deemed incorporated into, or to be part of, this report.
OMISSION OF CERTAIN INFORMATION
FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.

 

 

Forward-Looking Statements:This Form 10-Q includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements include declarations regarding management’s intents, beliefs and current expectations. These statements typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” “believe,” “estimate” and similar words. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements.
Actual results may differ materially due to:
•The speed and nature of increased competition in the electric utility industry and legislative and regulatory changes affecting how generation rates will be determined following the expiration of existing rate plans in Pennsylvania.
•The impact of the regulatory process on the pending matters in Ohio, Pennsylvania and New Jersey.
•Business and regulatory impacts from ATSI’s realignment into PJM.
•Economic or weather conditions affecting future sales and margins.
•Changes in markets for energy services.
•Changing energy and commodity market prices and availability.
•Replacement power costs being higher than anticipated or inadequately hedged.
•The continued ability of FirstEnergy’s regulated utilities to 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 regulations.
•The potential impacts of the proposed rules promulgated by EPA on July 6, 2010, in response to the U.S. Court of Appeals’ July 11, 2008 decision requiring revisions to the CAIR rules.
•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 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.

 

 

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

 

i

TABLE OF CONTENTS (Cont’d)
     
  Page 
     
Combined Notes To Consolidated Financial Statements
  26 
     
Item 2. Management’s Discussion and Analysis of Registrant and Subsidiaries
  6563 
     
Management’s Narrative Analysis of Results of Operations
    
     
FirstEnergy Solutions Corp.
  10399 
     
Ohio Edison Company
  106102 
     
The Cleveland Electric Illuminating Company
  108104 
     
The Toledo Edison Company
  110106 
     
Jersey Central Power & Light Company
  112108 
     
Metropolitan Edison Company
  114110 
     
Pennsylvania Electric Company
  116112
     
Item 3. Quantitative and Qualitative Disclosures About Market Risk
  118114 
     
Item 4. Controls and Procedures — FirstEnergy
  118114 
     
Item 4T. Controls and Procedures — FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec
  118114 
     
Part II. Other Information
    
     
Item 1. Legal Proceedings
  119114 
     
Item 1A. Risk Factors
  119114 
     
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
  119114 
     
Item 5. Other Information
  119114 
     
Item 6. Exhibits
  120115 
     
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

 

ii

GLOSSARY OF TERMS
The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its current and former subsidiaries:
   
ATSI American Transmission Systems, Incorporated, owns and operates transmission facilities
CEI The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
FENOC FirstEnergy Nuclear Operating Company, operates nuclear generating facilities
FES FirstEnergy Solutions Corp., provides energy-related products and services
FESC FirstEnergy Service Company, provides legal, financial and other corporate support services
FEV FirstEnergy Ventures Corp., invests in certain unregulated enterprises and business ventures
FGCO FirstEnergy Generation Corp., owns and operates non-nuclear generating facilities
FirstEnergy FirstEnergy Corp., a public utility holding company
Global RailA 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 Boich Companies,WMB Loan Ventures LLC, that owns mining and coal transportation operations near Roundup, Montana
TE The Toledo Edison Company, an Ohio electric utility operating subsidiary
Utilities OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec
The following abbreviations and acronyms are used to identify frequently used terms in this report:
   
AEPAmerican Electric Power Company, Inc.
ALJ Administrative Law Judge
AOCL Accumulated Other Comprehensive Loss
AQC Air Quality Control
ARO Asset Retirement Obligation
BGS
CAA		 Basic Generation Service
CAAClean Air Act
CAIR Clean Air Interstate Rule
CAMR Clean Air Mercury Rule
CATRClean 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)
EDCPExecutive Deferred Compensation Plan
EE&C Energy Efficiency and Conservation
EMAACEastern Mid-Atlantic Area Council
EMP Energy Master Plan
EPA United States Environmental Protection Agency
EPRIElectric Power Research Institute

 

iii

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
MAACMid-Atlantic Area Council
MACT Maximum Achievable Control Technology
MDPSC Maryland Public Service Commission
MEIUGMet-Ed Industrial users Group
MISO Midwest Independent Transmission System Operator, Inc.
Moody’s Moody’s Investors Service, Inc.
MRO Market Rate Offer
MTEPMISO 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
NYSEGNew York State Electric and Gas
OCCOhio Consumers’ Counsel
OCI Other Comprehensive Income
OPEB Other Post-Employment Benefits
OVEC Ohio Valley Electric Corporation
PCRB Pollution Control Revenue Bond
PICAPennsylvania 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
PPUCPennsylvania Public Utility Commission
PUCO Public Utilities Commission of Ohio
RCPRate Certainty Plan
RECs Renewable Energy Credits
RFP Request for Proposal
RPMReliability Pricing Model
RTEP Regional Transmission Expansion Plan
RTC Regulatory Transition Charge
RTO Regional Transmission Organization
S&P Standard & Poor’s Ratings Service
SB221 Amended Substitute Senate Bill 221
SBC Societal Benefits Charge

 

iv

GLOSSARY OF TERMS, Cont’d.
   
SEC U.S. Securities and Exchange Commission
SIP State Implementation Plan(s) Under the Clean Air Act
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
VIEVariable Interest Entity

 

v

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
                         
 Three Months Six Months  Three Months Nine Months 
 Ended June 30 Ended June 30  Ended September 30 Ended September 30 
 2010 2009 2010 2009  2010 2009 2010 2009 
 (In millions, except per share amounts)  (In millions, except per share amounts) 
REVENUES:
  
Electric utilities $2,373 $2,791 $4,916 $5,811  $2,757 $2,940 $7,673 $8,751 
Unregulated businesses 755 480 1,511 794  936 468 2,449 1,262 
                  
Total revenues* 3,128 3,271 6,427 6,605  3,693 3,408 10,122 10,013 
                  
  
EXPENSES:
  
Fuel 350 276 684 588  400 302 1,084 890 
Purchased power 1,052 1,024 2,290 2,167  1,284 1,313 3,574 3,480 
Other operating expenses 673 612 1,374 1,439  738 665 2,112 2,103 
Provision for depreciation 190 185 383 362  182 188 565 550 
Amortization of regulatory assets 161 233 373 642  176 261 549 903 
Deferral of new regulatory assets —  (45) —  (136) — — —  (136)
General taxes 176 184 381 395  206 192 587 587 
Impairment of long-lived assets 292 — 294 — 
                  
Total expenses 2,602 2,469 5,485 5,457  3,278 2,921 8,765 8,377 
                  
  
OPERATING INCOME
 526 802 942 1,148  415 487 1,357 1,636 
                  
  
OTHER INCOME (EXPENSE):
  
Investment income 31 27 47 16  46 191 93 207 
Interest expense  (207)  (206)  (420)  (400)  (208)  (355)  (628)  (755)
Capitalized interest 40 33 81 61  41 35 122 96 
                  
Total other expense  (136)  (146)  (292)  (323)  (121)  (129)  (413)  (452)
                  
  
INCOME BEFORE INCOME TAXES
 390 656 650 825  294 358 944 1,184 
  
INCOME TAXES
 134 248 245 302  119 128 364 430 
                  
  
NET INCOME
 256 408 405 523  175 230 580 754 
  
Noncontrolling interest loss  (9)  (6)  (15)  (10)
Loss attributable to noncontrolling interest  (4)  (4)  (19)  (14)
                  
  
EARNINGS AVAILABLE TO FIRSTENERGY CORP.
 $265 $414 $420 $533  $179 $234 $599 $768 
                  
  
BASIC EARNINGS PER SHARE OF COMMON STOCK
 $0.87 $1.36 $1.38 $1.75  $0.59 $0.77 $1.97 $2.52 
                  
  
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING
 304 304 304 304  304 304 304 304 
                  
  
DILUTED EARNINGS PER SHARE OF COMMON STOCK
 $0.87 $1.36 $1.37 $1.75  $0.59 $0.77 $1.96 $2.51 
                  
  
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING
 305 305 305 306  305 306 305 306 
                  
  
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK
 $— $— $0.55 $0.55  $1.10 $1.10 $1.65 $1.65 
                  
   
* Includes excise tax collections of $99$120 million and $95$106 million in the three months ended JuneSeptember 30, 2010 and 2009, respectively, and $208$328 million and $204$310 million in the sixnine months ended JuneSeptember 30, 2010 and 2009, respectively.
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

1

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

 

2

FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                
 June 30, December 31,  September 30, December 31, 
 2010 2009  2010 2009 
 (In millions)  (In millions) 
ASSETS
  
  
CURRENT ASSETS:
  
Cash and cash equivalents $281 $874  $632 $874 
Receivables-  
Customers (less allowances of $33 million in 2010 and 2009) 1,409 1,244 
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) 146 153  150 153 
Materials and supplies, at average cost 675 647  652 647 
Prepaid taxes 397 248  291 248 
Other 206 154  252 154 
          
 3,114 3,320  3,391 3,320 
          
PROPERTY, PLANT AND EQUIPMENT:
  
In service 28,274 27,826  27,590 27,826 
Less — Accumulated provision for depreciation 11,724 11,397  11,206 11,397 
          
 16,550 16,429  16,384 16,429 
Construction work in progress 3,000 2,735  3,154 2,735 
          
 19,550 19,164  19,538 19,164 
          
INVESTMENTS:
  
Nuclear plant decommissioning trusts 1,880 1,859  1,965 1,859 
Investments in lease obligation bonds 486 543  486 543 
Other 589 621  564 621 
          
 2,955 3,023  3,015 3,023 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Goodwill 5,575 5,575  5,575 5,575 
Regulatory assets 2,313 2,356  2,246 2,356 
Power purchase contract asset 134 200  116 200 
Other 825 666  826 666 
          
 8,847 8,797  8,763 8,797 
          
 $34,466 $34,304  $34,707 $34,304 
          
LIABILITIES AND CAPITALIZATION
  
  
CURRENT LIABILITIES:
  
Currently payable long-term debt $1,571 $1,834  $1,590 $1,834 
Short-term borrowings 1,463 1,181  1,000 1,181 
Accounts payable 848 829  813 829 
Accrued taxes 256 314  230 314 
Other 907 1,130  1,339 1,130 
          
 5,045 5,288  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  31 31 
Other paid-in capital 5,440 5,448  5,445 5,448 
Accumulated other comprehensive loss  (1,379)  (1,415)  (1,350)  (1,415)
Retained earnings 4,747 4,495  4,591 4,495 
          
Total common stockholders’ equity 8,839 8,559  8,717 8,559 
Noncontrolling interest  (20)  (2)  (26)  (2)
          
Total equity 8,819 8,557  8,691 8,557 
Long-term debt and other long-term obligations 11,861 11,908  12,104 11,908 
          
 20,680 20,465  20,795 20,465 
          
NONCURRENT LIABILITIES:
  
Accumulated deferred income taxes 2,710 2,468  2,824 2,468 
Retirement benefits 1,531 1,534  1,541 1,534 
Asset retirement obligations 1,372 1,425  1,394 1,425 
Deferred gain on sale and leaseback transaction 976 993  968 993 
Power purchase contract liability 691 643  756 643 
Lease market valuation liability 239 262  228 262 
Other 1,222 1,226  1,229 1,226 
          
 8,741 8,551  8,940 8,551 
          
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 8)
 
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
 
 $34,466 $34,304  $34,707 $34,304 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

3

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
        
         Nine Months Ended 
 Six Months Ended  September 30 
 June 30  2010 2009 
 2010 2009  (In millions) 
 (In millions)  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income $405 $523  $580 $754 
Adjustments to reconcile net income to net cash from operating activities-  
Provision for depreciation 383 362  565 550 
Amortization of regulatory assets 373 642  549 903 
Deferral of new regulatory assets —  (136) —  (136)
Nuclear fuel and lease amortization 76 52  123 92 
Deferred purchased power and other costs  (146)  (135)  (192)  (235)
Deferred income taxes and investment tax credits, net 159 69  259 421 
Impairment of long-lived assets 294 — 
Investment impairment 19 39  21 39 
Gain on investment securities held in trusts  (39)  (172)
Loss on debt redemption — 142 
Deferred rents and lease market valuation liability  (62)  (59)  (21)  (20)
Stock-based compensation  (6)  (2)
Accrued compensation and retirement benefits  (27)  (93) 48 20 
Interest rate swap transactions 43 —  129 — 
Commodity derivative transactions, net  (29) 18   (40) 26 
Cash collateral received (paid), net  (63) 48 
Cash collateral paid, net  (54)  (85)
Pension trust contribution —  (500)
Decrease (increase) in operating assets-  
Receivables  (156) 32   (172) 78 
Materials and supplies  (17) 6   (6) 30 
Prepayments and other current assets  (81)  (179)  (4)  (349)
Increase (decrease) in operating liabilities-  
Accounts payable 18  (11)  (16)  (103)
Accrued taxes  (58)  (101)  (18)  (97)
Accrued interest 63 121 
Other 27 27  4  (15)
          
Net cash provided from operating activities 858 1,102  2,073 1,464 
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New Financing-  
Long-term debt — 1,679  251 4,151 
Short-term borrowings, net 281 — 
Redemptions and Repayments-  
Long-term debt  (407)  (881)  (422)  (2,213)
Short-term borrowings, net  (171)  (764)
Common stock dividend payments  (335)  (335)  (503)  (503)
Other  (23)  (37)  (25)  (54)
          
Net cash provided from (used for) financing activities  (484) 426   (870) 617 
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (997)  (1,143)  (1,467)  (1,575)
Proceeds from asset sales 116 19  117 19 
Sales of investment securities held in trusts 1,915 1,001  2,577 3,039 
Purchases of investment securities held in trusts  (1,934)  (1,041)  (2,610)  (3,101)
Customer acquisition costs  (105) —   (110) — 
Cash investments 59 40  56  (4)
Restricted funds for debt redemption —  (150)
Other  (21)  (49)  (8)  (16)
          
Net cash used for investing activities  (967)  (1,173)  (1,445)  (1,788)
          
  
Net change in cash and cash equivalents  (593) 355   (242) 293 
Cash and cash equivalents at beginning of period 874 545  874 545 
          
Cash and cash equivalents at end of period $281 $900  $632 $838 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

4

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                         
 Three Months Ended Six Months Ended  Three Months Ended Nine Months Ended 
 June 30 June 30  September 30 September 30 
 2010 2009 2010 2009  2010 2009 2010 2009 
 (In thousands)  (In thousands) 
REVENUES:
  
Electric sales to affiliates $538,545 $839,751 $1,145,847 $1,732,441  $599,695 $616,300 $1,745,542 $2,348,741 
Electric sales to non-affiliates 728,803 205,379 1,397,488 485,125  904,752 443,819 2,302,240 928,944 
Other 47,326 296,022 159,432 349,692  49,230 44,453 208,662 394,145 
                  
Total revenues 1,314,674 1,341,152 2,702,767 2,567,258  1,553,677 1,104,572 4,256,444 3,671,830 
                  
  
EXPENSES:
  
Fuel 342,411 270,309 670,632 576,467  391,087 294,693 1,061,719 871,160 
Purchased power from affiliates 68,898 51,249 129,851 114,456  116,381 35,290 246,232 149,746 
Purchased power from non-affiliates 298,820 185,613 749,035 345,955  411,084 205,200 1,160,119 551,155 
Other operating expenses 303,895 278,264 608,406 585,620  309,793 305,935 916,366 891,555 
Provision for depreciation 63,319 65,548 126,237 126,921  59,298 66,041 185,535 192,962 
General taxes 22,272 21,285 49,018 44,661  21,804 21,700 70,822 66,361 
Impairment of long-lived assets 291,934 — 293,767 — 
                  
Total expenses 1,099,615 872,268 2,333,179 1,794,080  1,601,381 928,859 3,934,560 2,722,939 
                  
  
OPERATING INCOME
 215,059 468,884 369,588 773,178 
OPERATING INCOME (LOSS)
  (47,704) 175,713 321,884 948,891 
                  
  
OTHER INCOME (EXPENSE):
  
Investment income (loss) 13,366 5,643 14,083  (23,231)
Investment income 29,895 158,857 43,978 135,723 
Miscellaneous income 4,393 7,622 5,703 10,133  4,765 2,804 10,468 12,840 
Interest expense to affiliates  (2,560)  (3,315)  (4,865)  (6,294)
Interest expense — affiliates  (2,497)  (2,209)  (7,362)  (8,503)
Interest expense — other  (51,372)  (26,271)  (101,016)  (48,798)  (49,544)  (42,187)  (150,560)  (90,985)
Capitalized interest 23,905 14,028 43,595 24,106  22,955 17,869 66,550 41,975 
                  
Total other expense  (12,268)  (2,293)  (42,500)  (44,084)
Total other income (expense) 5,574 135,134  (36,926) 91,050 
                  
  
INCOME BEFORE INCOME TAXES
 202,791 466,591 327,088 729,094 
INCOME (LOSS) BEFORE INCOME TAXES
  (42,130) 310,847 284,958 1,039,941 
  
INCOME TAXES
 68,866 169,189 113,237 261,011   (5,404) 111,164 107,833 372,175 
                  
  
NET INCOME
 133,925 297,402 213,851 468,083 
NET INCOME (LOSS)
  (36,726) 199,683 177,125 667,766 
                  
  
OTHER COMPREHENSIVE INCOME:
 
OTHER COMPREHENSIVE INCOME (LOSS):
 
Pension and other postretirement benefits 885 72,121  (8,949) 74,689  886  (61,085)  (8,063) 13,604 
Unrealized gain on derivative hedges 3,017 15,041 4,291 26,057  2,818 790 7,109 26,847 
Change in unrealized gain on available-for-sale securities 6,060 39,504 11,088 38,027  17,445  (89,401) 28,533  (51,374)
                  
Other comprehensive income 9,962 126,666 6,430 138,773 
Income tax expense related to other comprehensive income 3,544 50,625 2,204 55,334 
Other comprehensive income (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, net of tax 6,418 76,041 4,226 83,439 
Other comprehensive income (loss), net of tax 13,455  (90,813) 17,681  (7,374)
                  
  
TOTAL COMPREHENSIVE INCOME
 $140,343 $373,443 $218,077 $551,522 
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.

 

5

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                
 June 30, December 31,  September 30, December 31, 
 2010 2009  2010 2009 
 (In thousands)  (In thousands) 
ASSETS
  
  
CURRENT ASSETS:
  
Cash and cash equivalents $11 $12  $10 $12 
Receivables-  
Customers (less accumulated provisions of $14,523,000 and $12,041,000, respectively, for uncollectible accounts) 315,178 195,107 
Customers (less accumulated provisions of $16,277,000 and $12,041,000, respectively, for uncollectible accounts) 325,265 195,107 
Associated companies 354,127 318,561  269,986 318,561 
Other (less accumulated provisions of $6,702,000 for uncollectible accounts) 36,392 51,872  57,407 51,872 
Notes receivable from associated companies 173,931 805,103  501,648 805,103 
Materials and supplies, at average cost 578,521 539,541  554,043 539,541 
Prepayments and other 172,514 107,782  204,065 107,782 
          
 1,630,674 2,017,978  1,912,424 2,017,978 
          
PROPERTY, PLANT AND EQUIPMENT:
  
In service 10,500,405 10,357,632  9,663,264 10,357,632 
Less — Accumulated provision for depreciation 4,695,180 4,531,158  4,114,381 4,531,158 
          
 5,805,225 5,826,474  5,548,883 5,826,474 
Construction work in progress 2,622,865 2,423,446  2,736,635 2,423,446 
          
 8,428,090 8,249,920  8,285,518 8,249,920 
          
INVESTMENTS:
  
Nuclear plant decommissioning trusts 1,107,594 1,088,641  1,158,376 1,088,641 
Other 7,965 22,466  7,400 22,466 
          
 1,115,559 1,111,107  1,165,776 1,111,107 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Accumulated deferred income tax benefits — 86,626  3,357 86,626 
Customer intangibles 118,219 16,566  127,420 16,566 
Goodwill 24,248 24,248  24,248 24,248 
Property taxes 50,125 50,125  50,125 50,125 
Unamortized sales and leaseback costs 77,646 72,553 
Unamortized sale and leaseback costs 61,934 72,553 
Other 128,315 121,665  164,332 121,665 
          
 398,553 371,783  431,416 371,783 
          
 $11,572,876 $11,750,788  $11,795,134 $11,750,788 
          
LIABILITIES AND CAPITALIZATION
  
  
CURRENT LIABILITIES:
  
Currently payable long-term debt $1,381,783 $1,550,927  $1,396,792 $1,550,927 
Short-term borrowings-  
Associated companies 85,128 9,237  9,642 9,237 
Other 100,000 100,000  100,000 100,000 
Accounts payable-  
Associated companies 412,507 466,078  472,018 466,078 
Other 236,720 245,363  204,928 245,363 
Accrued taxes 109,082 83,158  59,422 83,158 
Other 369,086 359,057  430,824 359,057 
          
 2,694,306 2,813,820  2,673,626 2,813,820 
          
CAPITALIZATION:
  
Common stockholders’ equity-  
Common stock, without par value, authorized 750 shares, 7 shares outstanding 1,467,158 1,468,423  1,490,010 1,468,423 
Accumulated other comprehensive loss  (98,775)  (103,001)  (85,320)  (103,001)
Retained earnings 2,363,000 2,149,149  2,326,274 2,149,149 
          
Total common stockholders’ equity 3,731,383 3,514,571  3,730,964 3,514,571 
Long-term debt and other long-term obligations 2,585,918 2,711,652  2,819,150 2,711,652 
          
 6,317,301 6,226,223  6,550,114 6,226,223 
          
NONCURRENT LIABILITIES:
  
Deferred gain on sale and leaseback transaction 976,012 992,869  967,583 992,869 
Accumulated deferred investment tax credits 56,310 58,396  55,267 58,396 
Asset retirement obligations 863,409 921,448  877,522 921,448 
Retirement benefits 223,853 204,035  228,779 204,035 
Property taxes 50,125 50,125  50,125 50,125 
Lease market valuation liability 239,447 262,200  228,119 262,200 
Other 152,113 221,672  163,999 221,672 
          
 2,561,269 2,710,745  2,571,394 2,710,745 
          
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 8)
 
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
 
 $11,572,876 $11,750,788  $11,795,134 $11,750,788 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

6

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
        
         Nine Months Ended 
 Six Months Ended  September 30 
 June 30  2010 2009 
 2010 2009  (In thousands) 
 (In thousands)  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income $213,851 $468,083  $177,125 $667,766 
Adjustments to reconcile net income to net cash from operating activities-  
Provision for depreciation 126,237 126,921  185,535 192,962 
Nuclear fuel and lease amortization 78,324 53,265  126,071 94,244 
Deferred rents and lease market valuation liability  (59,254)  (55,493)  (41,493)  (40,143)
Deferred income taxes and investment tax credits, net 113,978 63,309  96,152 268,812 
Impairment of long-lived assets 293,767 — 
Investment impairment 19,093 36,154  21,089 36,169 
Accrued compensation and retirement benefits 7,132  (10,594) 15,887 5,860 
Commodity derivative transactions, net  (29,308) 17,688   (40,048) 25,794 
Gain on asset sales  (1,021)  (9,635)  (2,213)  (9,832)
Gain on investment securities held in trusts  (34,292)  (154,723)
Cash collateral, net  (38,211) 40,471   (53,900)  (92,618)
Decrease (increase) in operating assets-  
Receivables  (192,792) 179,373   (91,134)  (55,774)
Materials and supplies  (28,470) 16,609   (15,324) 38,543 
Prepayments and other current assets 24,518 7,555  36,004  (35,315)
Increase (decrease) in operating liabilities-  
Accounts payable  (31,610)  (102,907)  (50,114)  (72,181)
Accrued taxes  (8,462)  (14,333)  (8,404) 23,846 
Accrued interest  (457) 1,871   (14,130) 31,770 
Other 24,907  (6,121) 23,349  (43,369)
          
Net cash provided from operating activities 218,455 812,216  623,927 881,811 
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New Financing-  
Long-term debt — 681,675  249,520 2,356,762 
Short-term borrowings, net 75,891 145,009  405 — 
Redemptions and Repayments-  
Long-term debt  (295,037)  (622,853)  (296,339)  (618,213)
Short-term borrowings, net —  (1,164,823)
Other  (686) —   (798)  (20,006)
          
Net cash provided from (used for) financing activities  (219,832) 203,831   (47,212) 553,720 
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (566,187)  (634,967)  (801,238)  (842,600)
Proceeds from asset sales 115,657 15,771  117,213 16,129 
Sales of investment securities held in trusts 956,813 537,078  1,478,086 2,152,717 
Purchases of investment securities held in trusts  (978,785)  (550,730)  (1,511,273)  (2,175,135)
Loans from (to) associated companies, net 631,172  (241,170) 303,455  (298,841)
Customer acquisition costs  (104,795) —   (110,073) — 
Leasehold improvement payments to associated companies  (51,204) —   (51,204) — 
Other  (1,295)  (22,034)  (1,683)  (20,882)
          
Net cash provided from (used for) investing activities 1,376  (896,052)
Net cash used for investing activities  (576,717)  (1,168,612)
          
  
Net change in cash and cash equivalents  (1) 119,995   (2) 266,919 
Cash and cash equivalents at beginning of period 12 39  12 39 
          
Cash and cash equivalents at end of period $11 $120,034  $10 $266,958 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

7

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                         
 Three Months Ended Six Months Ended  Three Months Ended Nine Months Ended 
 June 30 June 30  September 30 September 30 
 2010 2009 2010 2009  2010 2009 2010 2009 
 (In thousands)  (In thousands) 
STATEMENTS OF INCOME
  
  
REVENUES:
  
Electric sales $415,437 $647,224 $895,362 $1,367,235  $456,531 $575,377 $1,351,893 $1,942,612 
Excise and gross receipts tax collections 23,949 24,948 52,424 53,928  30,058 27,127 82,482 81,055 
                  
Total revenues 439,386 672,172 947,786 1,421,163  486,589 602,504 1,434,375 2,023,667 
                  
  
EXPENSES:
  
Purchased power from affiliates 114,414 314,870 250,271 647,206  136,804 200,506 424,530 847,712 
Purchased power from non-affiliates 98,462 98,330 210,513 236,143  84,264 161,732 257,322 397,875 
Other operating expenses 88,275 111,938 177,130 269,768  94,804 102,463 271,934 372,231 
Provision for depreciation 22,014 21,996 43,894 43,509  21,990 22,407 65,884 65,916 
Amortization of regulatory assets, net 9,424 22,295 38,769 42,506  9,704 17,404 48,473 59,910 
General taxes 43,362 43,903 90,854 93,023  48,909 45,164 139,763 138,187 
                  
Total expenses 375,951 613,332 811,431 1,332,155  396,475 549,676 1,207,906 1,881,831 
                  
  
OPERATING INCOME
 63,435 58,840 136,355 89,008  90,114 52,828 226,469 141,836 
                  
  
OTHER INCOME (EXPENSE):
  
Investment income 6,309 10,149 11,553 19,511  5,438 20,285 16,991 39,796 
Miscellaneous income 1,295 2,681 1,003 1,871  1,673 237 2,676 2,108 
Interest expense  (22,155)  (21,469)  (44,465)  (44,756)  (21,975)  (22,961)  (66,440)  (67,717)
Capitalized interest 295 279 503 499  335 231 838 730 
                  
Total other expense  (14,256)  (8,360)  (31,406)  (22,875)  (14,529)  (2,208)  (45,935)  (25,083)
                  
  
INCOME BEFORE INCOME TAXES
 49,179 50,480 104,949 66,133  75,585 50,620 180,534 116,753 
  
INCOME TAXES
 11,856 16,852 31,465 20,857  29,332 15,885 60,797 36,742 
                  
  
NET INCOME
 37,323 33,628 73,484 45,276  46,253 34,735 119,737 80,011 
                  
  
Noncontrolling interest income 130 143 262 289 
Income from noncontrolling interest 124 140 386 429 
                  
  
EARNINGS AVAILABLE TO PARENT
 $37,193 $33,485 $73,222 $44,987  $46,129 $34,595 $119,351 $79,582 
                  
  
STATEMENTS OF COMPREHENSIVE INCOME
  
  
NET INCOME
 $37,323 $33,628 $73,484 $45,276  $46,253 $34,735 $119,737 $80,011 
                  
  
OTHER COMPREHENSIVE INCOME (LOSS):
 
OTHER COMPREHENSIVE INCOME LOSS:
 
Pension and other postretirement benefits 322 89,864 4,337 95,602  321  (49,043) 4,658 46,559 
Change in unrealized gain on available-for-sale securities 520 728 811  (1,981) 2,178  (7,695) 2,989  (9,676)
                  
Other comprehensive income 842 90,592 5,148 93,621 
Income tax expense (benefit) related to other 
comprehensive income  (26) 37,310 667 37,839 
Other comprehensive income (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, net of tax 868 53,282 4,481 55,782 
Other comprehensive income (loss), net of tax 1,937  (34,814) 6,418 20,968 
                  
  
COMPREHENSIVE INCOME
 38,191 86,910 77,965 101,058 
COMPREHENSIVE INCOME (LOSS)
 48,190  (79) 126,155 100,979 
  
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST
 130 143 262 289  124 140 386 429 
                  
  
COMPREHENSIVE INCOME AVAILABLE TO PARENT
 $38,061 $86,767 $77,703 $100,769 
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.

 

8

OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                
 June 30, December 31,  September 30, December 31, 
 2010 2009  2010 2009 
 (In thousands)  (In thousands) 
ASSETS
  
CURRENT ASSETS:
  
Cash and cash equivalents $51,679 $324,175  $288,092 $324,175 
Receivables-  
Customers (less accumulated provisions of $4,685,000 and $5,119,000, respectively, for uncollectible accounts) 202,983 209,384 
Customers (less accumulated provisions of $4,951,000 and $5,119,000, respectively, for uncollectible accounts) 182,894 209,384 
Associated companies 68,005 98,874  38,499 98,874 
Other (less accumulated provisions of $6,000 and $18,000, respectively, for uncollectible accounts) 13,065 14,155 
Other 20,777 14,155 
Notes receivable from associated companies 106,232 118,651  16,234 118,651 
Prepayments and other 14,748 15,964  9,490 15,964 
          
 456,712 781,203  555,986 781,203 
          
UTILITY PLANT:
  
In service 3,086,689 3,036,467  3,118,239 3,036,467 
Less — Accumulated provision for depreciation 1,189,802 1,165,394  1,199,401 1,165,394 
          
 1,896,887 1,871,073  1,918,838 1,871,073 
Construction work in progress 36,866 31,171  38,915 31,171 
          
 1,933,753 1,902,244  1,957,753 1,902,244 
          
OTHER PROPERTY AND INVESTMENTS:
  
Investment in lease obligation bonds 204,812 216,600  204,707 216,600 
Nuclear plant decommissioning trusts 126,405 120,812  129,685 120,812 
Other 96,633 96,861  96,897 96,861 
          
 427,850 434,273  431,289 434,273 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Regulatory assets 422,559 465,331  413,596 465,331 
Pension assets 36,199 19,881  39,271 19,881 
Property taxes 67,037 67,037  67,037 67,037 
Unamortized sales and leaseback costs 32,626 35,127 
Unamortized sale and leaseback costs 31,376 35,127 
Other 17,765 39,881  17,540 39,881 
          
 576,186 627,257  568,820 627,257 
          
 $3,394,501 $3,744,977  $3,513,848 $3,744,977 
          
LIABILITIES AND CAPITALIZATION
  
CURRENT LIABILITIES:
  
Currently payable long-term debt $7,975 $2,723  $1,479 $2,723 
Short-term borrowings-  
Associated companies — 92,863  47,648 92,863 
Other 653 807  320 807 
Accounts payable-  
Associated companies 54,891 102,763  32,084 102,763 
Other 31,087 40,423  23,994 40,423 
Accrued taxes 55,976 81,868  55,236 81,868 
Accrued interest 25,639 25,749  25,354 25,749 
Other 79,382 81,424  133,060 81,424 
          
 255,603 428,620  319,175 428,620 
          
CAPITALIZATION:
  
Common stockholder’s equity-  
Common stock, without par value, authorized 175,000,000 shares - 60 shares outstanding 949,822 1,154,797  951,839 1,154,797 
Accumulated other comprehensive loss  (159,096)  (163,577)  (157,159)  (163,577)
Retained earnings 58,112 29,890  104,241 29,890 
          
Total common stockholder’s equity 848,838 1,021,110  898,921 1,021,110 
Noncontrolling interest 6,100 6,442  6,225 6,442 
          
Total equity 854,938 1,027,552  905,146 1,027,552 
Long-term debt and other long-term obligations 1,152,303 1,160,208  1,152,370 1,160,208 
          
 2,007,241 2,187,760  2,057,516 2,187,760 
          
NONCURRENT LIABILITIES:
  
Accumulated deferred income taxes 678,669 660,114  678,815 660,114 
Accumulated deferred investment tax credits 10,882 11,406  10,521 11,406 
Retirement benefits 171,056 174,925  169,070 174,925 
Asset retirement obligations 81,941 85,926  83,194 85,926 
Other 189,109 196,226  195,557 196,226 
          
 1,131,657 1,128,597  1,137,157 1,128,597 
          
COMMITMENTS AND CONTINGENCIES (Note 8)
 
COMMITMENTS AND CONTINGENCIES (Note 9)
 
 $3,394,501 $3,744,977  $3,513,848 $3,744,977 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

9

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
        
         Nine Months Ended 
 Six Months Ended  September 30 
 June 30  2010 2009 
 2010 2009  (In thousands) 
 (In thousands)  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income $73,484 $45,276  $119,737 $80,011 
Adjustments to reconcile net income to net cash from operating activities-  
Provision for depreciation 43,894 43,509  65,884 65,916 
Amortization of regulatory assets, net 38,769 42,506  48,473 59,910 
Purchased power cost recovery reconciliation  (1,514) 11,068  3,906 15,372 
Amortization of lease costs  (4,619)  (4,540) 28,314 28,394 
Deferred income taxes and investment tax credits, net 4,964  (11,252) 7,612 32,658 
Accrued compensation and retirement benefits  (16,154)  (4,593)  (16,659)  (3,542)
Accrued regulatory obligations  (2,309) 18,350  1,301 19,172 
Electric service prepayment programs —  (4,603) —  (4,634)
Cash collateral from suppliers 1,215 6,380  23,286 6,469 
Pension trust contributions —  (103,035)
Decrease (increase) in operating assets-  
Receivables 49,250  (16,509) 91,971 128,688 
Prepayments and other current assets 5,072  (6,290) 10,331  (2,553)
Increase (decrease) in operating liabilities- 
Decrease in operating liabilities- 
Accounts payable  (57,208)  (4,820)  (87,108)  (60,125)
Accrued taxes  (25,685)  (19,523)  (26,425)  (17,196)
Accrued interest  (110) 36   (395)  (59)
Other  (4) 10,086   (9,695)  (8,596)
          
Net cash provided from operating activities 109,045 105,081  260,533 236,850 
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New Financing-  
Long-term debt — 100,000  — 100,000 
Short-term borrowings, net — 114,617  — 74,514 
Redemptions and Repayments-  
Long-term debt  (2,957)  (100,984)  (9,628)  (101,088)
Short-term borrowings, net  (93,017) —   (45,702) — 
Common stock dividend payments  (250,000)  (125,000)  (250,000)  (150,000)
Other  (881)  (1,627)  (892)  (2,138)
          
Net cash used for financing activities  (346,855)  (12,994)  (306,222)  (78,712)
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (71,698)  (69,512)  (110,645)  (108,253)
Lease improvement payments from associated companies 18,375 — 
Leasehold improvement payments from associated companies 18,375 — 
Sales of investment securities held in trusts 59,804 24,941  78,599 207,280 
Purchases of investment securities held in trusts  (64,063)  (30,877)  (83,725)  (214,592)
Loan repayments from associated companies, net 12,420 51,803  102,417 134,975 
Cash investments 11,774 7,929  12,296 7,070 
Other  (1,298) 1,098   (7,711)  (1,216)
          
Net cash used for investing activities  (34,686)  (14,618)
Net cash provided from investing activities 9,606 25,264 
          
  
Net change in cash and cash equivalents  (272,496) 77,469   (36,083) 183,402 
Cash and cash equivalents at beginning of period 324,175 146,343  324,175 146,343 
          
Cash and cash equivalents at end of period $51,679 $223,812  $288,092 $329,745 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

10

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                         
 Three Months Ended Six Months Ended  Three Months Ended Nine Months Ended 
 June 30 June 30  September 30 September 30 
 2010 2009 2010 2009  2010 2009 2010 2009 
 (In thousands)  (In thousands) 
STATEMENTS OF INCOME
  
 
REVENUES:
  
Electric sales $280,180 $458,287 $592,677 $889,692  $309,236 $417,900 $901,913 $1,307,592 
Excise tax collections 15,495 16,799 33,068 35,119  19,480 17,629 52,548 52,748 
                  
Total revenues 295,675 475,086 625,745 924,811  328,716 435,529 954,461 1,360,340 
                  
  
EXPENSES:
  
Purchased power from affiliates 83,532 243,499 178,497 482,371  89,389 153,556 298,204 635,927 
Purchased power from non-affiliates 48,541 49,414 100,367 121,160  35,151 87,689 105,200 208,849 
Other operating expenses 28,937 39,177 60,172 104,007  36,441 37,822 96,613 141,829 
Provision for depreciation 18,336 17,852 36,447 36,132  18,057 17,753 54,504 53,885 
Amortization of regulatory assets 30,807 29,580 75,946 286,317  45,136 39,313 121,082 325,630 
Deferral of new regulatory assets —  (39,771) —  (134,587) — — —  (134,587)
General taxes 28,840 36,856 67,329 74,997  39,878 37,752 107,207 112,749 
                  
Total expenses 238,993 376,607 518,758 970,397  264,052 373,885 782,810 1,344,282 
                  
  
OPERATING INCOME (LOSS)
 56,682 98,479 106,987  (45,586)
OPERATING INCOME
 64,664 61,644 171,651 16,058 
                  
  
OTHER INCOME (EXPENSE):
  
Investment income 6,605 7,614 14,152 16,034  6,604 7,565 20,756 23,599 
Miscellaneous expense 675 798 1,257 2,792 
Miscellaneous income 533 645 1,790 3,437 
Interest expense  (33,262)  (32,757)  (66,883)  (66,079)  (33,384)  (34,740)  (100,267)  (100,819)
Capitalized interest 7 51 33 118  10 27 43 145 
                  
Total other expense  (25,975)  (24,294)  (51,441)  (47,135)  (26,237)  (26,503)  (77,678)  (73,638)
                  
  
INCOME (LOSS) BEFORE INCOME TAXES
 30,707 74,185 55,546  (92,721) 38,427 35,141 93,973  (57,580)
  
INCOME TAX EXPENSE (BENEFIT)
 8,785 26,461 19,628  (35,045) 13,479 9,755 33,107  (25,290)
                  
  
NET INCOME (LOSS)
 21,922 47,724 35,918  (57,676) 24,948 25,386 60,866  (32,290)
                  
  
Noncontrolling interest income 366 419 785 877 
Income from noncontrolling interest 366 418 1,151 1,295 
                  
  
EARNINGS (LOSS) AVAILABLE TO PARENT
 $21,556 $47,305 $35,133 $(58,553) $24,582 $24,968 $59,715 $(33,585)
                  
  
STATEMENTS OF COMPREHENSIVE INCOME
  
  
NET INCOME (LOSS)
 $21,922 $47,724 $35,918 $(57,676) $24,948 $25,386 $60,866 $(32,290)
                  
  
OTHER COMPREHENSIVE INCOME (LOSS):
  
Pension and other postretirement benefits 3,228 43,903  (19,357) 47,870  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 17,936  (7,301) 19,306  976  (17,854)  (6,325) 1,452 
                  
Other comprehensive income (loss), net of tax 2,252 25,967  (12,056) 28,564  2,252  (31,621)  (9,804)  (3,057)
                  
  
COMPREHENSIVE INCOME (LOSS)
 24,174 73,691 23,862  (29,112) 27,200  (6,235) 51,062  (35,347)
  
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST
 366 419 785 877  366 418 1,151 1,295 
                  
  
COMPREHENSIVE INCOME (LOSS) AVAILABLE TO PARENT
 $23,808 $73,272 $23,077 $(29,989) $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.

 

11

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                
 June 30, December 31,  September 30, December 31, 
 2010 2009  2010 2009 
 (In thousands)  (In thousands) 
ASSETS
  
  
CURRENT ASSETS:
  
Cash and cash equivalents $245 $86,230  $247 $86,230 
Receivables-  
Customers (less accumulated provisions of $4,809,000 and $5,239,000, respectively, for uncollectible accounts) 198,970 209,335 
Customers (less accumulated provisions of $5,271,000 and $5,239,000, respectively, for uncollectible accounts) 186,044 209,335 
Associated companies 73,008 98,954  59,339 98,954 
Other 10,377 11,661  4,910 11,661 
Notes receivable from associated companies 24,480 26,802  23,905 26,802 
Prepayments and other 4,390 9,973  4,362 9,973 
          
 311,470 442,955  278,807 442,955 
          
UTILITY PLANT:
  
In service 2,350,804 2,310,074  2,373,419 2,310,074 
Less — Accumulated provision for depreciation 911,368 888,169  921,040 888,169 
          
 1,439,436 1,421,905  1,452,379 1,421,905 
Construction work in progress 30,665 36,907  30,482 36,907 
          
 1,470,101 1,458,812  1,482,861 1,458,812 
          
OTHER PROPERTY AND INVESTMENTS:
  
Investment in lessor notes 340,033 388,641  340,031 388,641 
Other 10,108 10,220  10,084 10,220 
          
 350,141 398,861  350,115 398,861 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Goodwill 1,688,521 1,688,521  1,688,521 1,688,521 
Regulatory assets 468,119 545,505  420,144 545,505 
Pension assets (Note 5) — 13,380 
Pension assets (Note 6) — 13,380 
Property taxes 77,319 77,319  77,319 77,319 
Other 12,912 12,777  12,897 12,777 
          
 2,246,872 2,337,502  2,198,881 2,337,502 
          
 $4,378,584 $4,638,130  $4,310,664 $4,638,130 
          
LIABILITIES AND CAPITALIZATION
  
  
CURRENT LIABILITIES:
  
Currently payable long-term debt $137 $117  $148 $117 
Short-term borrowings-  
Associated companies 224,031 339,728  129,912 339,728 
Accounts payable-  
Associated companies 35,605 68,634  14,803 68,634 
Other 15,707 17,166  13,725 17,166 
Accrued taxes 77,051 90,511  64,492 90,511 
Accrued interest 18,557 18,466  39,261 18,466 
Other 49,897 45,440  63,732 45,440 
          
 420,985 580,062  326,073 580,062 
          
CAPITALIZATION:
  
Common stockholders’ equity-  
Common stock, without par value, authorized 105,000,000 shares, 67,930,743 shares outstanding 884,878 884,897  886,927 884,897 
Accumulated other comprehensive loss  (150,214)  (138,158)  (147,962)  (138,158)
Retained earnings 532,380 597,248  556,963 597,248 
          
Total common stockholders’ equity 1,267,044 1,343,987  1,295,928 1,343,987 
Noncontrolling interest 18,017 20,592  17,651 20,592 
          
Total equity 1,285,061 1,364,579  1,313,579 1,364,579 
Long-term debt and other long-term obligations 1,852,488 1,872,750  1,852,511 1,872,750 
          
 3,137,549 3,237,329  3,166,090 3,237,329 
          
NONCURRENT LIABILITIES:
  
Accumulated deferred income taxes 632,696 644,745  628,244 644,745 
Accumulated deferred investment tax credits 11,415 11,836  11,205 11,836 
Retirement benefits 81,872 69,733  82,070 69,733 
Other 94,067 94,425  96,982 94,425 
          
 820,050 820,739  818,501 820,739 
          
COMMITMENTS AND CONTINGENCIES (Note 8)
 
COMMITMENTS AND CONTINGENCIES (Note 9)
 
 $4,378,584 $4,638,130  $4,310,664 $4,638,130 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

12

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
        
         Nine Months Ended 
 Six Months Ended  September 30 
 June 30  2010 2009 
 2010 2009  (In thousands) 
 (In thousands)  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income (Loss) $35,918 $(57,676) $60,866 $(32,290)
Adjustments to reconcile net income (loss) to net cash from operating activities-  
Provision for depreciation 36,447 36,132  54,504 53,885 
Amortization of regulatory assets, net 75,946 286,317  121,082 325,630 
Deferral of new regulatory assets —  (134,587) —  (134,587)
Purchased power cost recovery reconciliation — 2,072  —  (3,478)
Deferred income taxes and investment tax credits, net  (18,083)  (58,506)  (24,283)  (41,939)
Accrued compensation and retirement benefits 5,421 2,092  10,467 10,311 
Accrued regulatory obligations  (444) 12,057 
Pension trust contribution —  (89,789)
Electric service prepayment programs —  (3,510) —  (3,510)
Cash collateral from suppliers 685 5,365 
Cash collateral from suppliers, net 19,245 5,404 
Decrease (increase) in operating assets-  
Receivables 51,757  (84,469) 86,725 30,977 
Prepayments and other current assets 5,392  (1,145) 5,421  (633)
Increase (decrease) in operating liabilities-  
Accounts payable  (34,488) 18,991   (57,272)  (32,240)
Accrued taxes  (11,317)  (29,434)  (23,876)  (17,003)
Accrued interest 91 232  20,795 29,816 
Other 1,932 3,265  740 11,489 
          
Net cash provided from (used for) operating activities 149,257  (2,804)
Net cash provided from operating activities 274,414 112,043 
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New Financing-  
Short-term borrowings, net — 47,423 
Long-term debt — 298,398 
Redemptions and Repayments-  
Long-term debt  (54)  (368)  (84)  (558)
Short-term borrowings, net  (136,013) —   (230,132)  (111,128)
Common stock dividend payments  (100,000)  (25,000)  (100,000)  (93,000)
Other  (3,367)  (3,019)  (4,100)  (6,161)
          
Net cash provided from (used for) financing activities  (239,434) 19,036   (334,316) 87,551 
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (44,373)  (46,434)  (70,812)  (73,577)
Loan repayments from (loans to) associated companies, net 2,322  (5,449)
Restricted cash —  (155,573)
Loan repayments from (to) associated companies, net 2,897  (4,638)
Redemptions of lessor notes 48,608 37,070  48,610 37,072 
Other  (2,365)  (1,415)  (6,776)  (2,871)
          
Net cash provided from (used for) investing activities 4,192  (16,228)
Net cash used for investing activities  (26,081)  (199,587)
          
  
Net change in cash and cash equivalents  (85,985) 4   (85,983) 7 
Cash and cash equivalents at beginning of period 86,230 226  86,230 226 
          
Cash and cash equivalents at end of period $245 $230  $247 $233 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

13

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                                
 Three Months Ended Six Months Ended  Three Months Ended Nine Months Ended 
 June 30 June 30  September 30 September 30 
 2010 2009 2010 2009  2010 2009 2010 2009 
 (In thousands)  (In thousands) 
STATEMENTS OF INCOME
  
  
REVENUES:
  
Electric sales $114,691 $219,911 $240,122 $456,996  $136,058 $206,086 $376,180 $663,082 
Excise tax collections 6,059 6,297 13,100 14,026  7,979 7,422 21,079 21,448 
                  
Total revenues 120,750 226,208 253,222 471,022  144,037 213,508 397,259 684,530 
                  
  
EXPENSES:
  
Purchased power from affiliates 38,654 130,564 85,654 255,888  42,338 86,278 144,062 342,166 
Purchased power from non-affiliates 23,675 18,244 49,784 58,781  16,663 56,494 50,377 115,275 
Other operating expenses 25,499 35,480 51,044 80,484  28,746 30,238 79,790 110,722 
Provision for depreciation 8,013 7,717 15,963 15,289  7,800 7,847 23,763 23,136 
Amortization (deferral) of regulatory assets, net  (1,800) 11,771  (10,299) 21,668  6,591 9,253  (3,708) 30,921 
General taxes 12,282 12,349 25,743 26,599  14,023 13,205 39,766 39,804 
                  
Total expenses 106,323 216,125 217,889 458,709  116,161 203,315 334,050 662,024 
                  
  
OPERATING INCOME
 14,427 10,083 35,333 12,313  27,876 10,193 63,209 22,506 
                  
  
OTHER INCOME (EXPENSE):
  
Investment income 5,057 7,529 8,857 13,013  3,018 9,302 11,875 22,315 
Miscellaneous income (expense)  (945) 1,375  (2,351) 35 
Miscellaneous expense  (502)  (1,725)  (2,853)  (1,690)
Interest expense  (10,455)  (9,262)  (20,942)  (14,795)  (10,479)  (10,854)  (31,421)  (25,649)
Capitalized interest 80 50 158 92  94 46 252 138 
                  
Total other expense  (6,263)  (308)  (14,278)  (1,655)  (7,869)  (3,231)  (22,147)  (4,886)
                  
  
INCOME BEFORE INCOME TAXES
 8,164 9,775 21,055 10,658  20,007 6,962 41,062 17,620 
  
INCOME TAXES
 948 3,370 6,330 3,261 
INCOME TAX EXPENSE (BENEFIT)
 6,911  (138) 13,241 3,123 
                  
  
NET INCOME
 7,216 6,405 14,725 7,397  13,096 7,100 27,821 14,497 
                  
  
Noncontrolling interest income 2 1 5 3 
Income from noncontrolling interest  (4) 14 1 17 
                  
  
EARNINGS AVAILABLE TO PARENT
 $7,214 $6,404 $14,720 $7,394  $13,100 $7,086 $27,820 $14,480 
                  
  
STATEMENTS OF COMPREHENSIVE INCOME
  
  
NET INCOME
 $7,216 $6,405 $14,725 $7,397  $13,096 $7,100 $27,821 $14,497 
                  
  
OTHER COMPREHENSIVE INCOME (LOSS):
  
Pension and other postretirement benefits 714 19,016 1,010 19,149  713  (24,201) 1,723  (5,052)
Change in unrealized gain on available-for-sale securities  (330)  (2,739) 39  (3,548) 427  (11,633) 466  (15,181)
                  
Other comprehensive income 384 16,277 1,049 15,601 
Income tax expense related to other comprehensive income 65 7,224 235 7,205 
Other comprehensive income (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, net of tax 319 9,053 814 8,396 
Other comprehensive income (loss), net of tax 810  (22,647) 1,624  (14,251)
                  
  
COMPREHENSIVE INCOME
 7,535 15,458 15,539 15,793 
COMPREHENSIVE INCOME (LOSS)
 13,906  (15,547) 29,445 246 
  
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST
 2 1 5 3 
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTEREST
  (4) 14 1 17 
                  
  
COMPREHENSIVE INCOME AVAILABLE TO PARENT
 $7,533 $15,457 $15,534 $15,790 
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.

 

14

THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                
 June 30, December 31,  September 30, December 31, 
 2010 2009  2010 2009 
 (In thousands)  (In thousands) 
ASSETS
  
  
CURRENT ASSETS:
  
Cash and cash equivalents $77,843 $436,712  $134,158 $436,712 
Receivables-  
Customers 128 75  30 75 
Associated companies 52,068 90,191  44,075 90,191 
Other (less accumulated provisions of $298,000 and $208,000, respectively, for uncollectible accounts) 18,866 20,180 
Other (less accumulated provisions of $224,000 and $208,000, respectively, for uncollectible accounts) 19,146 20,180 
Notes receivable from associated companies 95,919 85,101  81,254 85,101 
Prepayments and other 3,503 7,111  4,272 7,111 
          
 248,327 639,370  282,935 639,370 
          
UTILITY PLANT:
  
In service 932,788 912,930  938,532 912,930 
Less — Accumulated provision for depreciation 437,327 427,376  440,510 427,376 
          
 495,461 485,554  498,022 485,554 
Construction work in progress 7,906 9,069  9,946 9,069 
          
 503,367 494,623  507,968 494,623 
          
OTHER PROPERTY AND INVESTMENTS:
  
Investment in lessor notes 103,872 124,357  103,848 124,357 
Nuclear plant decommissioning trusts 75,540 73,935  76,051 73,935 
Other 1,539 1,580  1,514 1,580 
          
 180,951 199,872  181,413 199,872 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Goodwill 500,576 500,576  500,576 500,576 
Regulatory assets 81,799 69,557  74,297 69,557 
Property taxes 23,658 23,658  23,658 23,658 
Other 38,655 55,622  27,215 55,622 
          
 644,688 649,413  625,746 649,413 
          
 $1,577,333 $1,983,278  $1,598,062 $1,983,278 
          
LIABILITIES AND CAPITALIZATION
  
  
CURRENT LIABILITIES:
  
Currently payable long-term debt $216 $222  $208 $222 
Accounts payable-  
Associated companies 16,535 78,341  8,644 78,341 
Other 6,972 8,312  6,212 8,312 
Notes payable to associated companies — 225,975  — 225,975 
Accrued taxes 20,069 25,734  17,904 25,734 
Lease market valuation liability 36,900 36,900  36,900 36,900 
Other 22,244 29,273  44,745 29,273 
          
 102,936 404,757  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  147,010 147,010 
Other paid-in-capital 178,136 178,181  178,170 178,181 
Accumulated other comprehensive loss  (48,989)  (49,803)  (48,179)  (49,803)
Retained earnings 99,210 214,490  112,310 214,490 
          
Total common stockholders’ equity 375,367 489,878  389,311 489,878 
Noncontrolling interest 2,590 2,696  2,587 2,696 
          
Total equity 377,957 492,574  391,898 492,574 
Long-term debt and other long-term obligations 600,463 600,443  600,478 600,443 
          
 978,420 1,093,017  992,376 1,093,017 
          
NONCURRENT LIABILITIES:
  
Accumulated deferred income taxes 112,670 80,508  116,090 80,508 
Accumulated deferred investment tax credits 6,148 6,367  6,039 6,367 
Retirement benefits 67,507 65,988  67,953 65,988 
Asset retirement obligations 27,819 32,290  28,287 32,290 
Lease market valuation liability 217,750 236,200  208,525 236,200 
Other 64,083 64,151  64,179 64,151 
          
 495,977 485,504  491,073 485,504 
          
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 8)
 
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
 
 $1,577,333 $1,983,278  $1,598,062 $1,983,278 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

15

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
        
         Nine Months Ended 
 Six Months Ended  September 30 
 June 30  2010 2009 
 2010 2009  (In thousands) 
 (In thousands)  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income $14,725 $7,397  $27,821 $14,497 
Adjustments to reconcile net income to net cash from operating activities-  
Provision for depreciation 15,963 15,289  23,763 23,136 
Amortization (deferral) of regulatory assets, net  (10,299) 21,668   (3,708) 30,921 
Purchased power cost recovery reconciliation 60  (4,197)
Deferred rents and lease market valuation liability  (42,264)  (40,697)  (36,123)  (34,556)
Deferred income taxes and investment tax credits, net 16,503  (1,206) 18,927  (2,242)
Accrued compensation and retirement benefits 2,600 711  4,529 3,039 
Accrued regulatory obligations  (632) 4,450   40  4,841 
Electric service prepayment programs —  (1,458) —  (1,458)
Pension trust contribution —  (21,590)
Cash collateral from suppliers 343 2,755  9,874 2,830 
Decrease (increase) in operating assets- 
Decrease in operating assets- 
Receivables 52,754 1,075  61,051 24,561 
Prepayments and other current assets 3,608  (220) 2,839 109 
Increase (decrease) in operating liabilities-  
Accounts payable  (61,195) 5,533   (69,846)  (13,440)
Accrued taxes  (4,007)  (2,936)  (6,172)  (5,057)
Accrued interest — 3,983  10,050 14,033 
Other  (9,020) 1,788   (10,971)  (3,694)
          
Net cash provided from (used for) operating activities  (20,861) 13,935 
Net cash provided from operating activities 32,074 35,930 
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New Financing-  
Long-term debt — 297,422  — 297,422 
Short-term borrowings, net — 59,938 
Redemptions and Repayments-  
Long-term debt  (111)  (236)  (167)  (292)
Short-term borrowings, net  (225,975) —   (225,975)  (101,569)
Common stock dividend payments  (130,000)  (25,000)  (130,000)  (25,000)
Other  (112)  (247)  (112)  (351)
          
Net cash provided from (used for) financing activities  (356,198) 331,877   (356,254) 170,210 
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (20,237)  (21,661)  (29,592)  (33,005)
Leasehold improvement payments from associated companies 32,829 —  32,829 — 
Loans to associated companies, net  (10,818)  (19,819)
Loan repayments from associated companies, net 3,847 10,256 
Redemptions of lessor notes 20,485 18,330  20,509 18,358 
Sales of investment securities held in trusts 106,814 77,323  118,360 171,061 
Purchases of investment securities held in trusts  (107,978)  (78,700)  (119,777)  (173,214)
Other  (2,905)  (1,845)  (4,550)  (2,776)
          
Net cash provided from (used for) investing activities 18,190  (26,372) 21,626  (9,320)
          
  
Net change in cash and cash equivalents  (358,869) 319,440   (302,554) 196,820 
Cash and cash equivalents at beginning of period 436,712 14  436,712 14 
          
Cash and cash equivalents at end of period $77,843 $319,454  $134,158 $196,834 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

16

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                                
 Three Months Ended Six Months Ended  Three Months Ended Nine Months Ended 
 June 30 June 30  September 30 September 30 
 2010 2009 2010 2009  2010 2009 2010 2009 
 (In thousands)  (In thousands) 
REVENUES:
  
Electric sales $709,606 $697,061 $1,400,998 $1,457,981  $952,420 $854,108 $2,353,418 $2,312,089 
Excise tax collections 11,012 11,031 23,364 23,762  16,080 14,128 39,444 37,890 
                  
Total revenues 720,618 708,092 1,424,362 1,481,743  968,500 868,236 2,392,862 2,349,979 
                  
  
EXPENSES:
  
Purchased power 410,470 423,950 824,486 905,191  556,618 509,035 1,381,104 1,414,226 
Other operating expenses 75,177 70,876 170,837 156,746  89,167 84,495 260,004 241,241 
Provision for depreciation 27,093 25,301 55,064 50,404  26,614 26,565 81,678 76,969 
Amortization of regulatory assets, net 81,326 80,018 150,774 166,849  100,476 96,051 251,250 262,900 
General taxes 14,902 12,587 31,338 30,083  19,974 18,344 51,312 48,427 
                  
Total expenses 608,968 612,732 1,232,499 1,309,273  792,849 734,490 2,025,348 2,043,763 
                  
  
OPERATING INCOME
 111,650 95,360 191,863 172,470  175,651 133,746 367,514 306,216 
                  
  
OTHER INCOME (EXPENSE):
  
Miscellaneous income 1,649 2,007 3,482 2,812  1,662 1,301 5,144 4,113 
Interest expense  (30,041)  (29,671)  (59,464)  (57,539)  (30,220)  (29,593)  (89,684)  (87,132)
Capitalized interest 156 218 289 280  199 139 488 419 
                  
Total other expense  (28,236)  (27,446)  (55,693)  (54,447)  (28,359)  (28,153)  (84,052)  (82,600)
                  
  
INCOME BEFORE INCOME TAXES
 83,414 67,914 136,170 118,023  147,292 105,593 283,462 223,616 
  
INCOME TAXES
 33,521 29,848 57,051 52,399  64,440 43,435 121,491 95,834 
                  
  
NET INCOME
 49,893 38,066 79,119 65,624  82,852 62,158 161,971 127,782 
                  
  
OTHER COMPREHENSIVE INCOME:
 
OTHER COMPREHENSIVE INCOME (LOSS):
 
Pension and other postretirement benefits 4,135 20,918 20,063 25,039  4,135  (51,932) 24,198  (26,893)
Unrealized gain on derivative hedges 69 69 138 138  69 69 207 207 
                  
Other comprehensive income 4,204 20,987 20,201 25,177 
Income tax expense related to other comprehensive income 1,441 11,059 7,999 12,489 
Other comprehensive income (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, net of tax 2,763 9,928 12,202 12,688 
Other comprehensive income (loss), net of tax 2,761  (30,568) 14,963  (17,880)
                  
  
TOTAL COMPREHENSIVE INCOME
 $52,656 $47,994 $91,321 $78,312  $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.

 

17

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                
 June 30, December 31,  September 30, December 31, 
 2010 2009  2010 2009 
 (In thousands)  (In thousands) 
ASSETS
  
 
CURRENT ASSETS:
  
Cash and cash equivalents $99 $27  $1 $27 
Receivables-  
Customers (less accumulated provisions of $3,362,000 and $3,506,000, respectively, for uncollectible accounts) 345,136 300,991 
Customers (less accumulated provisions of $4,736,000 and $3,506,000, respectively, for uncollectible accounts) 378,822 300,991 
Associated companies 11,778 12,884  3,900 12,884 
Other 25,626 21,877  26,024 21,877 
Notes receivable — associated companies 17,883 102,932  64,168 102,932 
Prepaid taxes 146,898 34,930  71,153 34,930 
Other 11,357 12,945  15,674 12,945 
     
 558,777 486,586      
      559,742 486,586 
      
UTILITY PLANT:
  
In service 4,524,706 4,463,490  4,568,640 4,463,490 
Less — Accumulated provision for depreciation 1,651,304 1,617,639  1,666,918 1,617,639 
          
 2,873,402 2,845,851  2,901,722 2,845,851 
Construction work in progress 55,825 54,251  51,857 54,251 
          
 2,929,227 2,900,102  2,953,579 2,900,102 
          
 
OTHER PROPERTY AND INVESTMENTS:
  
Nuclear plant decommissioning trusts 166,148 166,768  175,254 166,768 
Nuclear fuel disposal trust 204,088 199,677  208,870 199,677 
Other 2,209 2,149  2,136 2,149 
     
 372,445 368,594      
      386,260 368,594 
      
DEFERRED CHARGES AND OTHER ASSETS:
  
Goodwill 1,810,936 1,810,936  1,810,936 1,810,936 
Regulatory assets 800,898 888,143  722,086 888,143 
Other 29,849 27,096  30,608 27,096 
          
 2,641,683 2,726,175  2,563,630 2,726,175 
          
 $6,502,132 $6,481,457  $6,463,211 $6,481,457 
          
LIABILITIES AND CAPITALIZATION
 
  
LIABILITIES AND CAPITALIZATION
 
CURRENT LIABILITIES:
  
Currently payable long-term debt $31,508 $30,639  $31,947 $30,639 
Short-term borrowings- 
Associated companies 57,850 — 
Accounts payable-  
Associated companies 15,158 26,882  12,743 26,882 
Other 202,049 168,093  154,872 168,093 
Accrued taxes 1,786 12,594  24,798 12,594 
Accrued interest 18,189 18,256  30,003 18,256 
Other 82,524 111,156  78,903 111,156 
     
 409,064 367,620      
      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  136,284 136,284 
Other paid-in capital 2,507,003 2,507,049  2,508,852 2,507,049 
Accumulated other comprehensive loss  (230,810)  (243,012)  (228,049)  (243,012)
Retained earnings 189,194 200,075  197,046 200,075 
          
Total common stockholders’ equity 2,601,671 2,600,396  2,614,133 2,600,396 
Long-term debt and other long-term obligations 1,787,235 1,801,589  1,779,081 1,801,589 
          
 4,388,906 4,401,985  4,393,214 4,401,985 
          
 
NONCURRENT LIABILITIES:
  
Accumulated deferred income taxes 705,219 687,545  720,825 687,545 
Nuclear fuel disposal costs 196,623 196,511  196,703 196,511 
Retirement benefits 132,565 150,603  133,579 150,603 
Asset retirement obligations 104,878 101,568  106,573 101,568 
Power purchase contract liability 378,448 399,105  386,273 399,105 
Other 186,429 176,520  192,778 176,520 
          
 1,704,162 1,711,852  1,736,731 1,711,852 
          
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 8)
 
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
 
 $6,502,132 $6,481,457  $6,463,211 $6,481,457 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

18

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
        
         Nine Months Ended 
 Six Months Ended  September 30 
 June 30  2010 2009 
 2010 2009  (In thousands) 
 (In thousands)  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income $79,119 $65,624  $161,971 $127,782 
Adjustments to reconcile net income to net cash from operating activities-  
Provision for depreciation 55,064 50,404  81,678 76,969 
Amortization of regulatory assets, net 150,774 166,849  251,250 262,900 
Deferred purchased power and other costs  (67,664)  (50,542)  (85,136)  (106,340)
Deferred income taxes and investment tax credits, net  (1,425) 3,440  14,984 40,989 
Accrued compensation and retirement benefits 2,608  (2,883) 11,621 7,308 
Cash collateral paid, net  (23,400)  (209)  (23,400)  (210)
Pension trust contribution —  (100,000)
Decrease (increase) in operating assets-  
Receivables  (46,788) 41,228   (72,994) 18,984 
Prepayments and other current assets  (112,155)  (145,740)  (36,573)  (83,538)
Increase (decrease) in operating liabilities-  
Accounts payable 11,924  (19,321)  (37,668)  (40,670)
Accrued taxes 10,368  (14,007) 35,326  (13,399)
Accrued interest  (67) 9,373  11,747 20,946 
Tax collections payable —  (9,714) —  (9,714)
Other  (6,192) 4,555   (13,953) 12,606 
          
Net cash provided from operating activities 52,166 99,057  298,853 214,613 
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New Financing-  
Long-term debt — 299,619  — 299,619 
Short-term borrowings, net 57,850 — 
Redemptions and Repayments-  
Common stock —  (150,000) —  (150,000)
Long-term debt  (13,830)  (13,093)  (21,703)  (20,570)
Short-term borrowings, net —  (56,267) —  (114,766)
Common stock dividend payments  (90,000)  (88,000)  (165,000)  (88,000)
Other —  (2,260)  (2)  (2,275)
          
Net cash used for financing activities  (45,980)  (10,001)  (186,705)  (75,992)
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (80,727)  (78,401)  (130,008)  (121,342)
Loan repayments from (loans to) associated companies, net 85,049  (1,341)
Loans from (to) associated companies, net 38,764  (660)
Sales of investment securities held in trusts 281,242 244,880  340,368 338,684 
Purchases of investment securities held in trusts  (289,454)  (252,856)  (353,028)  (351,216)
Other  (2,224)  (1,266)  (8,270)  (4,152)
          
Net cash used for investing activities  (6,114)  (88,984)  (112,174)  (138,686)
          
  
Net change in cash and cash equivalents 72 72   (26)  (65)
Cash and cash equivalents at beginning of period 27 66  27 66 
          
Cash and cash equivalents at end of period $99 $138  $1 $1 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

19

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                                
 Three Months Ended Six Months Ended  Three Months Ended Nine Months Ended 
 June 30 June 30  September 30 September 30 
 2010 2009 2010 2009  2010 2009 2010 2009 
 (In thousands)  (In thousands) 
REVENUES:
  
Electric sales $422,030 $360,022 $873,590 $769,708  $460,864 $424,901 $1,334,454 $1,194,609 
Gross receipts tax collections 20,629 17,586 42,196 37,569  23,049 20,612 65,245 58,181 
                  
Total revenues 442,659 377,608 915,786 807,277  483,913 445,513 1,399,699 1,252,790 
                  
  
EXPENSES:
  
Purchased power from affiliates 149,000 78,652 310,080 178,729  166,039 94,768 476,119 273,497 
Purchased power from non-affiliates 85,276 123,299 177,204 247,210  87,561 142,495 264,765 389,705 
Other operating expenses 90,151 51,309 192,134 157,666  141,761 63,654 333,895 221,320 
Provision for depreciation 13,440 12,919 26,198 25,058  12,978 13,262 39,176 38,320 
Amortization of regulatory assets, net 48,589 61,548 97,389 89,139  15,480 84,631 112,869 173,770 
General taxes 19,894 22,034 41,634 43,969  25,029 22,540 66,663 66,509 
                  
Total expenses 406,350 349,761 844,639 741,771  448,848 421,350 1,293,487 1,163,121 
                  
  
OPERATING INCOME
 36,309 27,847 71,147 65,506  35,065 24,163 106,212 89,669 
                  
  
OTHER INCOME (EXPENSE):
  
Interest income 880 2,769 2,097 5,955  581 2,169 2,678 8,124 
Miscellaneous income 1,381 1,058 3,554 1,914  1,539 1,068 5,093 2,982 
Interest expense  (13,002)  (14,763)  (26,775)  (28,122)  (13,037)  (14,380)  (39,812)  (42,502)
Capitalized interest 159 62 285 77  176 47 461 124 
                  
Total other expense  (10,582)  (10,874)  (20,839)  (20,176)  (10,741)  (11,096)  (31,580)  (31,272)
                  
  
INCOME BEFORE INCOME TAXES
 25,727 16,973 50,308 45,330  24,324 13,067 74,632 58,397 
  
INCOME TAXES
 8,618 6,968 20,884 18,703  10,084 2,324 30,968 21,027 
                  
  
NET INCOME
 17,109 10,005 29,424 26,627  14,240 10,743 43,664 37,370 
                  
  
OTHER COMPREHENSIVE INCOME:
 
OTHER COMPREHENSIVE INCOME (LOSS):
 
Pension and other postretirement benefits 2,162 27,369 11,871 31,922  2,161  (31,365) 14,032 557 
Unrealized gain on derivative hedges 84 84 168 168  84 84 252 252 
                  
Other comprehensive income 2,246 27,453 12,039 32,090 
Income tax expense related to other comprehensive income 724 13,592 4,901 15,385 
Other comprehensive income (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, net of tax 1,522 13,861 7,138 16,705 
Other comprehensive income (loss), net of tax 1,522  (18,169) 8,660  (1,464)
                  
  
TOTAL COMPREHENSIVE INCOME
 $18,631 $23,866 $36,562 $43,332 
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.

 

20

METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                
 June 30, December 31,  September 30, December 31, 
 2010 2009  2010 2009 
 (In thousands)  (In thousands) 
ASSETS
  
 
CURRENT ASSETS:
  
Cash and cash equivalents $126 $120  $124 $120 
Receivables-  
Customers (less accumulated provisions of $3,877,000 and $4,044,000, respectively, for uncollectible accounts) 188,771 171,052 
Customers (less accumulated provisions of $4,344,000 and $4,044,000, respectively, for uncollectible accounts) 182,509 171,052 
Associated companies 45,551 29,413  41,689 29,413 
Other 13,221 11,650  13,654 11,650 
Notes receivable from associated companies 11,207 97,150  11,201 97,150 
Prepaid taxes 46,475 15,229  27,307 15,229 
Other 649 1,459  2,523 1,459 
          
 306,000 326,073  279,007 326,073 
          
UTILITY PLANT:
  
In service 2,196,713 2,162,815  2,213,765 2,162,815 
Less — Accumulated provision for depreciation 830,042 810,746  836,821 810,746 
          
 1,366,671 1,352,069  1,376,944 1,352,069 
Construction work in progress 30,214 14,901  31,488 14,901 
          
 1,396,885 1,366,970  1,408,432 1,366,970 
          
OTHER PROPERTY AND INVESTMENTS:
  
Nuclear plant decommissioning trusts 263,752 266,479  277,823 266,479 
Other 881 890  877 890 
          
 264,633 267,369  278,700 267,369 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Goodwill 416,499 416,499  416,499 416,499 
Regulatory assets 385,392 356,754  400,375 356,754 
Power purchase contract asset 120,436 176,111  103,902 176,111 
Other 42,546 36,544  64,084 36,544 
          
 964,873 985,908  984,860 985,908 
          
 $2,932,391 $2,946,320  $2,950,999 $2,946,320 
          
LIABILITIES AND CAPITALIZATION
 
  
LIABILITIES AND CAPITALIZATION
 
CURRENT LIABILITIES:
  
Currently payable long-term debt $28,500 $128,500  $28,500 $128,500 
Short-term borrowings-  
Associated companies 17,898 —  6,296 — 
Accounts payable-  
Associated companies 51,308 40,521  34,204 40,521 
Other 30,997 41,050  28,604 41,050 
Accrued taxes 20,689 11,170  2,967 11,170 
Accrued interest 16,085 17,362  11,717 17,362 
Other 28,588 24,520  31,993 24,520 
          
 194,065 263,123  144,281 263,123 
          
CAPITALIZATION:
  
Common stockholders’ equity-  
Common stock, without par value, authorized 900,000 shares, 859,500 shares outstanding 1,197,014 1,197,070  1,197,064 1,197,070 
Accumulated other comprehensive loss  (136,413)  (143,551)  (134,891)  (143,551)
Retained earnings 33,824 4,399  48,064 4,399 
          
Total common stockholders’ equity 1,094,425 1,057,918  1,110,237 1,057,918 
Long-term debt and other long-term obligations 713,920 713,873  713,941 713,873 
          
 1,808,345 1,771,791  1,824,178 1,771,791 
          
NONCURRENT LIABILITIES:
  
Accumulated deferred income taxes 454,777 453,462  489,608 453,462 
Accumulated deferred investment tax credits 7,090 7,313  6,978 7,313 
Nuclear fuel disposal costs 44,416 44,391  44,434 44,391 
Retirement benefits 29,194 33,605  28,268 33,605 
Asset retirement obligations 186,373 180,297  189,489 180,297 
Power purchase contract liability 158,987 143,135  175,259 143,135 
Other 49,144 49,203  48,504 49,203 
          
 929,981 911,406  982,540 911,406 
          
COMMITMENTS AND CONTINGENCIES (Note 8)
 
COMMITMENTS AND CONTINGENCIES (Note 9)
 
 $2,932,391 $2,946,320  $2,950,999 $2,946,320 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

21

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
        
         Nine Months Ended 
 Six Months Ended  September 30 
 June 30  2010 2009 
 2010 2009  (In thousands) 
 (In thousands)  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income $29,424 $26,627  $43,664 $37,370 
Adjustments to reconcile net income to net cash from operating activities-  
Provision for depreciation 26,198 25,058  39,176 38,320 
Amortization of regulatory assets, net 97,389 89,139  112,869 173,770 
Deferral of regulatory assets  (38,358)  (47,592)
Deferred costs recoverable as regulatory assets  (49,646)  (70,044)
Deferred income taxes and investment tax credits, net  (12,079) 30,135  23,781 59,393 
Accrued compensation and retirement benefits  (1,573) 3,250   (282) 6,712 
Cash collateral received (paid), net 50  (6,800)
Pension trust contribution —  (123,521)
Cash collateral paid, net  (17,647)  (6,800)
Decrease (increase) in operating assets-  
Receivables  (29,439) 346   (18,444)  (23,370)
Prepayments and other current assets  (30,436)  (39,068)  (13,144)  (22,614)
Increase (decrease) in operating liabilities-  
Accounts payable 733  (18,624)  (18,763)  (17,293)
Accrued taxes 9,519  (1,754)  (8,203)  (11,095)
Accrued interest  (1,277) 10,230   (5,645) 5,001 
Other 6,743 7,870  7,721 11,891 
          
Net cash provided from operating activities 56,894 78,817  95,437 57,720 
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New Financing-  
Long-term debt — 300,000  — 300,000 
Short-term borrowings, net 17,898 —  6,296 — 
Redemptions and Repayments-  
Long-term debt  (100,000) —   (100,000) — 
Short-term borrowings, net —  (15,003) —  (265,003)
Other —  (2,267) —  (2,268)
          
Net cash provided from (used for) financing activities  (82,102) 282,730   (93,704) 32,729 
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (54,405)  (48,464)  (77,921)  (73,106)
Sales of investment securities held in trusts 376,610 63,086  420,116 88,802 
Purchases of investment securities held in trusts  (381,219)  (67,668)  (427,150)  (95,982)
Loans from (to) associated companies, net 85,943  (306,448) 85,949  (6,586)
Other  (1,715)  (2,072)  (2,723)  (3,597)
          
Net cash provided from (used for) investing activities 25,214  (361,566)
Net cash used for investing activities  (1,729)  (90,469)
          
  
Net change in cash and cash equivalents 6  (19) 4  (20)
Cash and cash equivalents at beginning of period 120 144  120 144 
          
Cash and cash equivalents at end of period $126 $125  $124 $124 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

22

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                                
 Three Months Ended Six Months Ended  Three Months Ended Nine Months Ended 
 June 30 June 30  September 30 September 30 
 2010 2009 2010 2009  2010 2009 2010 2009 
 (In thousands)  (In thousands) 
REVENUES:
  
Electric sales $350,335 $316,881 $736,271 $688,174  $372,480 $340,246 $1,108,751 $1,028,420 
Gross receipts tax collections 16,162 14,804 33,686 32,096  17,414 15,246 51,100 47,342 
                  
Total revenues 366,497 331,685 769,957 720,270  389,894 355,492 1,159,851 1,075,762 
                  
  
EXPENSES:
  
Purchased power from affiliates 152,945 72,166 321,345 168,247  165,125 81,191 486,470 249,438 
Purchased power from non-affiliates 86,829 125,317 178,252 252,483  92,648 144,777 270,900 397,260 
Other operating expenses 67,070 46,301 139,464 123,590  58,832 47,785 198,296 171,375 
Provision for depreciation 16,605 15,581 31,287 30,036  14,859 15,038 46,146 45,074 
Amortization (deferral) of regulatory assets, net  (10,522) 18,113  (20,488) 26,889   (1,771) 17,201  (22,259) 44,090 
General taxes 18,647 18,251 35,181 38,844  19,194 17,230 54,375 56,074 
                  
Total expenses 331,574 295,729 685,041 640,089  348,887 323,222 1,033,928 963,311 
                  
  
OPERATING INCOME
 34,923 35,956 84,916 80,181  41,007 32,270 125,923 112,451 
                  
  
OTHER INCOME (EXPENSE):
  
Miscellaneous income 1,310 911 2,923 1,709  1,508 1,156 4,431 2,865 
Interest expense  (17,630)  (11,843)  (34,920)  (25,076)  (17,581)  (11,614)  (52,501)  (36,690)
Capitalized interest 183 29 323 51  193 23 516 74 
                  
Total other expense  (16,137)  (10,903)  (31,674)  (23,316)  (15,880)  (10,435)  (47,554)  (33,751)
                  
  
INCOME BEFORE INCOME TAXES
 18,786 25,053 53,242 56,865  25,127 21,835 78,369 78,700 
  
INCOME TAXES
 5,812 10,232 22,969 23,354  5,311 6,039 28,280 29,393 
                  
  
NET INCOME
 12,974 14,821 30,273 33,511  19,816 15,796 50,089 49,307 
                  
  
OTHER COMPREHENSIVE INCOME:
 
OTHER COMPREHENSIVE INCOME (LOSS):
 
Pension and other postretirement benefits 1,830 29,400 10,377 32,355  1,830  (79,579) 12,207  (47,224)
Unrealized gain on derivative hedges 16 16 32 32  16 17 48 49 
Change in unrealized gain on available-for-sale securities — 6 —  (16) — 19 — 3 
                  
Other comprehensive income 1,846 29,422 10,409 32,371 
Income tax expense related to other comprehensive income 483 15,100 3,767 16,155 
Other comprehensive income (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, net of tax 1,363 14,322 6,642 16,216 
Other comprehensive income (loss), net of tax 1,362  (46,402) 8,004  (30,186)
                  
  
TOTAL COMPREHENSIVE INCOME
 $14,337 $29,143 $36,915 $49,727 
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.

 

23

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                
 June 30, December 31,  September 30, December 31, 
 2010 2009  2010 2009 
 (In thousands)  (In thousands) 
ASSETS
  
 
CURRENT ASSETS:
  
Cash and cash equivalents $10 $14  $8 $14 
Receivables-  
Customers (less accumulated provisions of $3,428,000 and $3,483,000, respectively, for uncollectible accounts) 137,450 139,302 
Customers (less accumulated provisions of $3,481,000 and $3,483,000, respectively, for uncollectible accounts) 135,416 139,302 
Associated companies 88,612 77,338  95,355 77,338 
Other 10,934 18,320  14,413 18,320 
Notes receivable from associated companies 14,092 14,589  14,569 14,589 
Prepaid taxes 56,450 18,946  48,264 18,946 
Other 758 1,400  2,115 1,400 
          
 308,306 269,909  310,140 269,909 
          
UTILITY PLANT:
  
In service 2,481,942 2,431,737  2,503,555 2,431,737 
Less — Accumulated provision for depreciation 918,963 901,990  925,894 901,990 
          
 1,562,979 1,529,747  1,577,661 1,529,747 
Construction work in progress 22,319 24,205  28,498 24,205 
          
 1,585,298 1,553,952  1,606,159 1,553,952 
          
OTHER PROPERTY AND INVESTMENTS:
  
Nuclear plant decommissioning trusts 140,611 142,603  147,675 142,603 
Non-utility generation trusts 96,988 120,070  92,034 120,070 
Other 283 289  294 289 
          
 237,882 262,962  240,003 262,962 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Goodwill 768,628 768,628  768,628 768,628 
Regulatory assets 138,557 9,045  202,801 9,045 
Power purchase contract asset 6,031 15,362  5,746 15,362 
Other 20,245 19,143  28,780 19,143 
          
 933,461 812,178  1,005,955 812,178 
          
 $3,064,947 $2,899,001  $3,162,257 $2,899,001 
          
LIABILITIES AND CAPITALIZATION
  
 
CURRENT LIABILITIES:
  
Currently payable long-term debt $69,310 $69,310  $69,310 $69,310 
Short-term borrowings-  
Associated companies 66,786 41,473  43,244 41,473 
Accounts payable-  
Associated companies 48,876 39,884  40,747 39,884 
Other 28,460 41,990  28,427 41,990 
Accrued taxes 5,071 6,409  4,164 6,409 
Accrued interest 17,625 17,598  24,513 17,598 
Other 24,696 22,741  25,871 22,741 
          
 260,824 239,405  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  88,552 88,552 
Other paid-in capital 913,460 913,437  913,507 913,437 
Accumulated other comprehensive loss  (155,462)  (162,104)  (154,100)  (162,104)
Retained earnings 121,774 91,501  141,590 91,501 
          
Total common stockholders’ equity 968,324 931,386  989,549 931,386 
Long-term debt and other long-term obligations 1,072,199 1,072,181  1,072,207 1,072,181 
          
 2,040,523 2,003,567  2,061,756 2,003,567 
          
NONCURRENT LIABILITIES:
  
Accumulated deferred income taxes 296,829 242,040  356,536 242,040 
Retirement benefits 167,288 174,306  167,542 174,306 
Asset retirement obligations 94,933 91,841  96,519 91,841 
Power purchase contract liability 153,603 100,849  194,102 100,849 
Other 50,947 46,993  49,526 46,993 
          
 763,600 656,029  864,225 656,029 
          
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 8)
 
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
 
 $3,064,947 $2,899,001  $3,162,257 $2,899,001 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

24

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
        
         Nine Months Ended 
 Six Months Ended  September 30 
 June 30  2010 2009 
 2010 2009  (In thousands) 
 (In thousands)  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income $30,273 $33,511  $50,089 $49,307 
Adjustments to reconcile net income to net cash from operating activities-  
Provision for depreciation 31,287 30,036  46,146 45,074 
Amortization (deferral) of regulatory assets, net  (20,488) 26,889   (22,259) 44,090 
Deferred costs recoverable as regulatory assets  (38,955)  (46,349)  (61,574)  (76,953)
Deferred income taxes and investment tax credits, net 42,943 24,700  94,015 56,144 
Accrued compensation and retirement benefits 4,216 490  7,634 6,271 
Cash collateral  (3,613) 2 
Cash collateral paid, net  (11,760) — 
Pension trust contribution —  (60,000)
Decrease (increase) in operating assets-  
Receivables 3,266 42,494   (2,584) 3,687 
Prepayments and other current assets  (36,864)  (35,750)  (30,034)  (24,730)
Increase (decrease) in operating liabilities-  
Accounts payable  (4,603)  (10,108)  (12,766)  (8,988)
Accrued taxes  (1,339)  (7,629)  (2,245)  (7,015)
Accrued interest 28  (1,669) 6,915  (2,570)
Other 9,559 2,302  10,127 13,392 
          
Net cash provided from operating activities 15,710 58,919  71,704 37,709 
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New Financing-  
Long-term debt — 498,583 
Short-term borrowings, net 25,313 146,654  1,771 — 
Redemptions and Repayments-  
Long-term debt —  (100,000) —  (100,000)
Short-term borrowings, net —  (239,770)
Common stock dividend payments —  (35,000) —  (85,000)
Other 5 —   (125)  (3,865)
          
Net cash provided from financing activities 25,318 11,654  1,646 69,948 
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (58,293)  (59,606)  (91,924)  (92,070)
Loans from associated companies, net 498 63 
Sales of investment securities held in trusts 133,934 53,504  141,392 80,986 
Purchases of investment securities held in trusts  (113,067)  (60,378)  (116,240)  (91,105)
Other  (4,104)  (4,168)  (6,584)  (5,482)
          
Net cash used for investing activities  (41,032)  (70,585)  (73,356)  (107,671)
          
  
Net change in cash and cash equivalents  (4)  (12)  (6)  (14)
Cash and cash equivalents at beginning of period 14 23  14 23 
          
Cash and cash equivalents at end of period $10 $11  $8 $9 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

25

COMBINED NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
1. ORGANIZATION AND BASIS OF PRESENTATION
FirstEnergy is a diversified energy company that holds, directly or indirectly, all of the outstanding common stock of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), ATSI, JCP&L, Met-Ed, Penelec, FENOC, 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 6)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 Six Months  Three Months Nine Months 
Reconciliation of Basic and Diluted Earnings per Share Ended June 30 Ended June 30  Ended September 30 Ended September 30 
of Common Stock 2010 2009 2010 2009  2010 2009 2010 2009 
 (In millions, except per share amounts)  (In millions, except per share amounts) 
  
Earnings available to FirstEnergy Corp. $265 $414 $420 $533  $179 $234 $599 $768 
                  
  
Weighted average number of basic shares outstanding 304 304 304 304  304 304 304 304 
Assumed exercise of dilutive stock options and awards 1 1 1 2  1 2 1 2 
                  
Weighted average number of diluted shares outstanding 305 305 305 306  305 306 305 306 
                  
  
Basic earnings per share of common stock $0.87 $1.36 $1.38 $1.75  $0.59 $0.77 $1.97 $2.52 
                  
Diluted earnings per share of common stock $0.87 $1.36 $1.37 $1.75  $0.59 $0.77 $1.96 $2.51 
                  

 

26

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.

27

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 JuneSeptember 30, 2010 and December 31, 2009:
                                
 June 30, 2010 December 31, 2009  September 30, 2010 December 31, 2009 
 Carrying Fair Carrying Fair  Carrying Fair Carrying Fair 
 Value Value Value Value  Value Value Value Value 
 (In millions)  (In millions) 
FirstEnergy $13,346 $14,992 $13,753 $14,502 
 
FirstEnergy (Consolidated) $13,592 $14,920 $13,753 $14,502 
FES 3,932 4,386 4,224 4,306  4,181 4,228 4,224 4,306 
OE 1,166 1,378 1,169 1,299  1,159 1,409 1,169 1,299 
CEI 1,853 2,110 1,873 2,032  1,853 2,144 1,873 2,032 
TE 600 682 600 638  600 706 600 638 
JCP&L 1,826 2,013 1,840 1,950  1,819 2,076 1,840 1,950 
Met-Ed 742 840 842 909  742 849 842 909 
Penelec 1,144 1,233 1,144 1,177  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 JuneSeptember 30, 2010 and December 31, 2009:
                                                                
 June 30, 2010(1) December 31, 2009(2)  September 30, 2010(1) December 31, 2009(2) 
 Cost Unrealized Unrealized Fair Cost Unrealized Unrealized Fair  Cost Unrealized Unrealized Fair Cost Unrealized Unrealized Fair 
 Basis Gains Losses Value Basis Gains Losses Value  Basis Gains Losses Value Basis Gains Losses Value 
 (In millions)  (In millions) 
Debt securities
  
FirstEnergy $1,404 $40 $— $1,444 $1,727 $22 $— $1,749  $1,795 $73 $— $1,868 $1,727 $22 $— $1,749 
FES 702 18 — 720 1,043 3 — 1,046  1,079 39 — 1,118 1,043 3 — 1,046 
OE 119 1 — 120 55 — — 55  124 4 — 128 55 — — 55 
TE 14 — — 14 72 — — 72  31 1 — 32 72 — — 72 
JCP&L 278 11 — 289 271 9 — 280  277 15 — 292 271 9 — 280 
Met-Ed 130 5 — 135 120 5 — 125  129 8 — 137 120 5 — 125 
Penelec 161 5 — 166 166 5 — 171  155 6 — 161 166 5 — 171 
  
Equity securities
  
FirstEnergy $250 $24 $— $274 $252 $43 $— $295  $261 $44 $— $305 $252 $43 $— $295 
JCP&L 74 4 — 78 74 11 — 85  78 9 — 87 74 11 — 85 
Met-Ed 117 14 — 131 117 23 — 140  122 23 — 145 117 23 — 140 
Penelec 59 6 — 65 61 9 — 70  62 10 — 72 61 9 — 70 
(1) Excludes cash balances: FirstEnergy — $463$93 million; FES — $388$40 million; OE — $6$2 million; TE — $61$44 million; JCP&L — $3$5 million; Met-Ed — $(2)$(5) million and Penelec - $7— $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.

 

2728

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 six-monthnine-month period ended JuneSeptember 30, 2010 and 2009 were as follows:
                                                        
June 30, 2010 FirstEnergy FES OE TE JCP&L Met-Ed Penelec 
September 30, 2010 FirstEnergy FES OE TE JCP&L Met-Ed Penelec 
 (In millions)  (In millions) 
Proceeds from sales $1,916 $957 $60 $107 $281 $377 $134  $2,577 $1,478 $79 $118 $340 $420 $141 
Realized gains 83 54 2 3 9 9 6  132 101 2 3 10 10 6 
Realized losses 86 58 — — 9 12 7  118 88 — 1 10 12 7 
Interest and dividend income 37 22 1 1 7 3 3  56 33 2 1 10 5 5 
                                                        
June 30, 2009 FirstEnergy FES OE TE JCP&L Met-Ed Penelec 
September 30, 2009 FirstEnergy FES OE TE JCP&L Met-Ed Penelec 
 (In millions)  (In millions) 
Proceeds from sales $1,001 $537  $25  $77 $245  $63  $54  $3,040 $2,153 $207 $171 $339 $89 $81 
Realized gains 30 24 -  3  3  1  -   186 162 11 7�� 4 1 1 
Realized losses 91 58 3 -  11 12  7   96 62 3 — 11 13 7 
Interest and dividend income 30  14 2 1  7  3  3   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 JuneSeptember 30, 2010 and December 31, 2009 (excluding2009:
                                 
  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 method investments and equity method investments totaling $256 million as of $251 millionSeptember 30, 2010, and $264 million respectively, thatas of December 31, 2009 are not required to be disclosed):
                                 
  June 30, 2010  December 31, 2009 
  Cost  Unrealized  Unrealized  Fair  Cost  Unrealized  Unrealized  Fair 
  Basis  Gains  Losses  Value  Basis  Gains  Losses  Value 
  (In millions) 
Debt Securities
                                
FirstEnergy $487  $93  $—  $580  $544  $72  $—  $616 
OE  205   55   —   260   217   29   —   246 
CEI  340   38   —   378   389   43   —   432 
disclosed and are therefore excluded from the amounts reported above.
Notes Receivable
The following table below provides the approximate fair value and related carrying amounts of notes receivable as of JuneSeptember 30, 2010 and December 31, 2009:2009. 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.
                                
 June 30, 2010 December 31, 2009  September 30, 2010 December 31, 2009 
 Carrying Fair Carrying Fair  Carrying Fair Carrying Fair 
 Value Value Value Value  Value Value Value Value 
 (In millions)  (In millions) 
Notes Receivable
  
FirstEnergy $36 $34 $36 $35  $7 $8 $36 $35 
FES — — 2 1  — — 2 1 
TE 104 117 124 141  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.

29

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

28

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

 

2930

                                                        
 Level 2  Level 2 
 FirstEnergy FES OE TE JCP&L Met-Ed Penelec  FirstEnergy FES OE TE JCP&L Met-Ed Penelec 
 (In millions)  (In millions) 
Assets
  
Nuclear Decommissioning Trust Investments
  
U.S. government debt securities $538 $265 $121 $14 $36 $92 $10  $619 $337 $127 $26 $37 $82 $10 
U.S. state debt securities 94 — — — 31 2 61  88 — — — 29 — 59 
Foreign government debt securities 297 297 — — — — —  285 285 — — — — — 
Corporate debt securities 225 158 — — 20 42 5  580 496 — 6 23 47 8 
Other 458 388 5 62 1 1 1  101 38 6 45 2 9 1 
                              
Total nuclear decommissioning trust investments
 $1,612 $1,108 $126 $76 $88 $137 $77 
Total Nuclear Decommissioning Trust Investments
 $1,673 $1,156 $133 $77 $91 $138 $78 
                              
  
Rabbi Trust Investments
  
Equity securities — financial $1 $— $— $— $— $— $—  $1 $— $— $— $— $— $— 
Other 12 — 1 — — — —  11 — — — — — — 
                              
Total rabbi trust investments
 $13 $— $1 $— $— $— $— 
Total Rabbi Trust Investments
 $12 $— $— $— $— $— $— 
                              
  
Nuclear Fuel Disposal Trust Investments
  
U.S. state debt securities $196 $— $— $— $196 $— $—  $209 $— $— $— $209 $— $— 
Other 8 — — — 8 — — 
                              
Total nuclear fuel disposal trust investments
 $204 $— $— $— $204 $— $— 
Total Nuclear Fuel Disposal Trust Investments
 $209 $— $— $— $209 $— $— 
                              
  
NUG Trust Investments
  
U.S. state debt securities $97 $— $— $— $— $— $97  $86 $— $— $— $— $— $86 
Other 6 — — — — — 6 
                              
Total NUG trust investments
 $97 $— $— $— $— $— $97 
Total NUG Trust Investments
 $92 $— $— $— $— $— $92 
                              
  
Derivatives
  
Commodity contracts $111 $102 $— $— $2 $5 $2  $183 $174 $— $— $2 $5 $2 
Interest rate contracts 62 — — — — — — 
                              
Total derivatives contracts
 $173 $102 $— $— $2 $5 $2 
Total Derivatives Contracts
 $183 $174 $— $— $2 $5 $2 
                              
Total Assets(1)
 $2,099 $1,210 $127 $76 $294 $142 $176 
Total Assets(2)
 $2,169 $1,330 $133 $77 $302 $143 $172 
                              
  
Liabilities
  
Derivatives
  
Commodity contracts $273 $273 $— $— $— $— $—  $329 $329 $— $— $— $— $— 
                              
Total Liabilities
 $273 $273 $— $— $— $— $—  $329 $329 $— $— $— $— $— 
                              
                                                        
 Level 3  Level 3 
 FirstEnergy FES OE TE JCP&L Met-Ed Penelec  FirstEnergy FES OE TE JCP&L Met-Ed Penelec 
 (In millions)  (In millions) 
Assets
  
Derivatives — NUG contracts(2)
 $134 $— $— $— $7 $121 $6 
Derivatives — NUG contracts(3)
 $116 $— $— $— $7 $104 $6 
                              
  
Liabilities
  
Derivatives — NUG contracts(2)
 $691 $— $— $— $378 $159 $154 
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 $(7)$(13) million of receivables, payables and accrued income.
 
(2)(3) NUG contracts are subject to regulatory accounting and do not impact earnings.

30

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

 

31

                                                        
 Level 2  Level 2 
 FirstEnergy FES OE TE JCP&L Met-Ed Penelec  FirstEnergy FES OE TE JCP&L Met-Ed Penelec 
 (In millions)  (In millions) 
Assets
  
Nuclear Decommissioning Trust Investments
  
U.S. government debt securities $558 $306 $118 $72 $23 $30 $9  $558 $306 $118 $72 $23 $30 $9 
U.S. state debt securities 188 15 — — 41 82 50  188 15 — — 41 82 50 
Foreign government debt securities 279 279 — — — — —  279 279 — — — — — 
Corporate debt securities 484 443 — — 15 20 6  484 443 — — 15 20 6 
Other 35 29 2 — 1 2 1  35 29 2 — 1 2 1 
                              
Total nuclear decommissioning trust investments
 $1,544 $1,072 $120 $72 $80 $134 $66 
Total Nuclear Decommissioning Trust Investments
 $1,544 $1,072 $120 $72 $80 $134 $66 
                              
  
Rabbi Trust Investments
  
Equity securities — financial $1 $— $— $— $— $— $—  $1 $— $— $— $— $— $— 
Other 9 — — — — — —  9 — — — — — — 
                              
Total rabbi trust investments
 $10 $— $— $— $— $— $— 
Total Rabbi Trust Investments
 $10 $— $— $— $— $— $— 
                              
  
Nuclear Fuel Disposal Trust Investments
  
U.S. state debt securities $189 $— $— $— $189 $— $—  $189 $— $— $— $189 $— $— 
Other 11 — — — 11 — —  11 — — — 11 — — 
                              
Total nuclear fuel disposal trust investments
 $200 $— $— $— $200 $— $— 
��               
Total Nuclear Fuel Disposal Trust Investments
 $200 $— $— $— $200 $— $— 
               
  
NUG Trust Investments
  
U.S. state debt securities $101 $— $— $— $— $— $101  $101 $— $— $— $— $— $101 
Other 19 — — — — — 19  19 — — — — — 19 
                              
Total NUG trust investments
 $120 $— $— $— $— $— $120 
Total NUG Trust Investments
 $120 $— $— $— $— $— $120 
                              
  
Derivatives — Commodity Contracts
 $34 $15 $— $— $5 $9 $5  $34 $15 $— $— $5 $9 $5 
  
Other
 $1 $— $— $— $— $— $—  $1 $— $— $— $— $— $— 
                              
Total Assets(1)(2)
 $1,909 $1,087 $120 $72 $285 $143 $191  $1,909 $1,087 $120 $72 $285 $143 $191 
                              
  
Liabilities
  
Derivatives — commodity contracts $224 $224 $— $— $— $— $—  $224 $224 $— $— $— $— $— 
                              
Total Liabilities
 $224 $224 $— $— $— $— $—  $224 $224 $— $— $— $— $— 
                              
                                                        
 Level 3  Level 3 
 FirstEnergy FES OE TE JCP&L Met-Ed Penelec  FirstEnergy FES OE TE JCP&L Met-Ed Penelec 
 (In millions)  (In millions) 
Assets
  
Derivatives — NUG contracts(2)
 $200 $— $— $— $9 $176 $15 
Derivatives — NUG contracts(3)
 $200 $— $— $— $9 $176 $15 
                              
  
Liabilities
  
Derivatives — NUG contracts(2)
 $643 $— $— $— $399 $143 $101 
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.
 
(1)(2) Excludes $21 million of receivables, payables and accrued income.
 
(2)(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.

 

32

The following tables set forth a reconciliation of changes in the fair value of NUG contracts classified as Level 3 in the fair value hierarchy for the three and sixnine months ended JuneSeptember 30, 2010 and 2009 (in millions):
                                
 FirstEnergy JCP&L Met-Ed Penelec  FirstEnergy JCP&L Met-Ed Penelec 
Balance as of January 1, 2010 $(444) $(391) $33 $(86) $(444) $(391) $33 $(86)
Settlements(1)
 146 70 36 40  209 99 60 50 
Unrealized losses(1)
  (259)  (50)  (107)  (102)  (405)  (88)  (164)  (153)
                  
Balance as of June 30, 2010 $(557) $(371) $(38) $(148)
Balance as of September 30, 2010 $(640) $(380) $(71) $(189)
                  
  
Balance as of April 1, 2010 $(590) $(394) $(30) $(166)
Balance as of July 1, 2010 $(557) $(371) $(38) $(148)
Settlements(1)
 68 30 19 19  63 29 23 11 
Unrealized losses(1)
  (35)  (7)  (27)  (1)  (146)  (38)  (56)  (52)
                  
Balance as of June 30, 2010 $(557) $(371) $(38) $(148)
Balance as of September 30, 2010 $(640) $(380) $(71) $(189)
                  
                                
 FirstEnergy JCP&L Met-Ed Penelec  FirstEnergy JCP&L Met-Ed Penelec 
Balance as of January 1, 2009 $(332) $(518) $150 $36  $(332) $(518) $150 $36 
Settlements(1)
 179 90 43 47  273 132 63 78 
Unrealized losses(1)
  (383)  (38)  (170)  (176)  (406)  (30)  (178)  (198)
                  
Balance as of June 30, 2009 $(536) $(466) $23 $(93)
Balance as of September 30, 2009 $(465) $(416) $35 $(84)
                  
  
Balance as of April 1, 2009 $(476) $(518) $76 $(34)
Balance as of July 1, 2009 $(536) $(466) $23 $(93)
Settlements(1)
 96 44 26 27  93 42 20 31 
Unrealized gains (losses)(1)
  (156) 8  (79)  (86)  (22) 8  (8)  (22)
                  
Balance as of June 30, 2009 $(536) $(466) $23 $(93)
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.
4.5. 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 JuneSeptember 30, 2010, an adverse 10% change in commodity prices would decrease net income by approximately $9$6 million ($64 million net of tax) during the next twelve months. A hypothetical 10% increase in the interest rates associated with variable-rate debt would decrease net income by less thanapproximately $1 million for the three and sixnine months ended JuneSeptember 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 JuneSeptember 30, 2010, no forward starting swap agreements were outstanding.
Total unamortized losses included in AOCL associated with prior interest rate cash flow hedges totaled $109$95 million ($7162 million net of tax) as of JuneSeptember 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 JuneSeptember 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)

 

33

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

Fair Value Hedges
FirstEnergy useshas 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 arewere treated as fair value hedges of fixed-rate, long-term debt issues, protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. In MayAs of September 30, 2010, FirstEnergy terminatedno fixed-for-floating interest rate swap agreements were outstanding.
Total unamortized gains included in long-term debt associated with a notional value of $3.15 billion, which resulted in cash proceeds of $43.1 million. These proceeds will generally be amortized to earnings over the life of the underlying debt.
Effective June 1, 2010, FirstEnergy executed multipleprior fixed-for-floating interest rate swap agreements with a combined notional valuetotaled $129 million ($84 million net of $3.2 billion, which essentially replaced the swap agreements terminated in Maytax) as of September 30, 2010. As of June 30, 2010, the debt underlying the $3.2 billion outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 6%, which the swaps have converted to aBased on current weighted average variable rate of 4%.
On July 16, 2010, FirstEnergy terminated these fixed-for-floating interest rate swap agreements with a notional value of $3.2 billion, which resulted in cash proceeds of $83.6 million. These proceedsestimates, approximately $22 million will be amortized to earnings overinterest expense during the life ofnext twelve months. Reclassifications from long-term debt into interest expense totaled $5 million and $7 million for the underlying debt. While FirstEnergy currently does not have any interest rate swaps outstanding, costs associated with entering into future swap transactions may be increased as a result of the recent passage of the Dodd-Frank Wall Street Reformthree and Consumer Protection Act, which requires increased regulation of swaps, swap dealers and major swap participants.nine months ended September 30, 2010.
The following tables summarize the fair value of interest rate swaps in FirstEnergy’s Consolidated Balance Sheets:
                   
Derivative Assets  Derivative Liabilities 
  Fair Value    Fair Value 
  June 30,  December 31,    June 30,  December 31, 
  2010  2009    2010  2009 
  (In millions)    (In millions) 
Fair Value Hedges         Fair Value Hedges        
Interest Rate Swaps $62  $—  Interest Rate Swaps $—  $— 
               
Noncurrent Assets $62  $—  Noncurrent Liabilities $—  $— 
               

Commodity Derivatives
FirstEnergy uses both physically and financially settled derivatives to manage its exposure to volatility in commodity prices. Commodity derivatives are used for risk management purposes to hedge exposures when it makes economic sense to do so, including circumstances where the hedging relationship does not qualify for hedge accounting.

34

The following tables summarize the fair value of commodity derivatives in FirstEnergy’s Consolidated Balance Sheets:
                                    
Cash Flow HedgesCash Flow Hedges 
Derivative AssetsDerivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities 
 Fair Value Fair Value  Fair Value Fair Value 
 June 30, December 31, June 30, December 31,  September 30, December 31, September 30, December 31, 
 2010 2009 2010 2009  2010 2009 2010 2009 
 (In millions) (In millions)  (In millions) (In millions) 
Cash Flow Hedges Cash Flow Hedges 
 
Electricity Forwards Electricity Forwards  Electricity Forwards 
Current Assets $40 $3 Current Liabilities $50 $7  $77 $3 Current Liabilities $87 $7 
NonCurrent Assets 57 11 NonCurrent Liabilities 54 12  73 11 NonCurrent Liabilities 70 12 
Natural Gas Futures Natural Gas Futures  Natural Gas Futures 
Current Assets — — Current Liabilities 4 9  — — Current Liabilities 1 9 
NonCurrent Assets — — NonCurrent Liabilities — —  — — NonCurrent Liabilities — — 
Other Other  Other 
Current Assets — — Current Liabilities 1 2  — — Current Liabilities — 2 
NonCurrent Assets — — NonCurrent Liabilities — —  — — NonCurrent Liabilities — — 
                      
 $97 $14   $109 $30  $150 $14   $158 $30 
                      
                                    
Economic HedgesEconomic Hedges 
Derivative AssetsDerivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities 
 Fair Value Fair Value  Fair Value Fair Value 
 June 30, December 31, June 30, December 31,  September 30, December 31, September 30, December 31, 
 2010 2009 2010 2009  2010 2009 2010 2009 
 (In millions) (In millions)  (In millions) (In millions) 
Economic Hedges Economic Hedges 
   
NUG Contracts NUG Contracts  NUG Contracts 
Power Purchase Power Purchase  Power Purchase 
Contract Asset $134 $200 Contract Liability $691 $643  $116 $200 Contract Liability $756 $643 
Other Other  Other 
Current Assets 4 — Current Liabilities 114 106  17 — Current Liabilities 138 106 
NonCurrent Assets 10 19 NonCurrent Liabilities 55 97  15 19 NonCurrent Liabilities 34 97 
                      
 148 219   860 846  148 219   928 846 
                      
Total Commodity Derivatives $245 $233 Total Commodity Derivatives $969 $876  $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 JuneSeptember 30, 2010:
                                
 Purchases Sales Net Units  Purchases Sales Net Units 
 (In thousands)  (In thousands) 
Electricity Forwards 21,596  (19,965) 1,631 MWH 28,456  (32,604)  (4,148) MWH
Heating Oil Futures 2,100 — 2,100 Gallons 840 — 840 Gallons
Natural Gas Futures 1,250  (1,000) 250 mmBtu 500  (500) — mmBtu

 

3534

The effect of derivative instruments on the consolidated statements of income and comprehensive income for the three and sixnine months ended JuneSeptember 30, 2010 and 2009, for instruments designated in cash flow hedging relationships and not in hedging relationships, respectively, are summarized in the following tables:
                                
 Three Months Ended June 30,  Three Months Ended September 30, 
 Electricity Natural Gas Heating Oil    Electricity Natural Gas Heating Oil   
Derivatives in Cash Flow Hedging Relationships Forwards Futures Futures Total  Forwards Futures Futures Total 
 (In millions)  (In millions) 
2010
  
Gain (Loss) Recognized in AOCL (Effective Portion) $(8) $— $— $(8) $(2) $— $— $(2)
Effective Gain (Loss) Reclassified to: (1)
  
Purchased Power Expense  (7) — —  (7)  (1) — —  (1)
Fuel Expense —  (3)  (1)  (4) —  (3)  (1)  (4)
  
2009
  
Gain (Loss) Recognized in AOCL (Effective Portion) $6 $— $2 $8  $15 $(2) $— $13 
Effective Gain (Loss) Reclassified to: (1)
  
Purchased Power Expense 1 — — 1  11 — — 11 
Fuel Expense —  (4)  (4)  (8) —  (4)  (2)  (6)
                                
 Six Months Ended June 30,  Nine Months Ended September 30, 
 Electricity Natural Gas Heating Oil    Electricity Natural Gas Heating Oil   
Derivatives in Cash Flow Hedging Relationships Forwards Futures Futures Total  Forwards Futures Futures Total 
 (In millions)  (In millions) 
2010
  
Gain (Loss) Recognized in AOCL (Effective Portion) $(13) $(1) $—  $(14) $(15) $(1) $— $(16)
Effective Gain (Loss) Reclassified to: (1)
  
Purchased Power Expense  (11) — —  (11)  (12) — —  (12)
Fuel Expense —  (6)  (2)  (8) —  (9)  (2)  (11)
  
2009
  
Gain (Loss) Recognized in AOCL (Effective Portion) $4 $(7) $1 $(2) $19 $(9) $— $10 
Effective Gain (Loss) Reclassified to: (1)
  
Purchased Power Expense  (17) — —  (17)  (6) — —  (6)
Fuel Expense —  (4)  (8)  (12) —  (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)
          

 

3635

                        
 Three Months Ended June 30,  Nine Months Ended September 30, 
 NUG      NUG     
Derivatives Not in Hedging Relationships Contracts Other Total  Contracts Other Total 
 (In millions)  (In millions) 
2010
  
Unrealized Gain (Loss) Recognized in:  
Purchased Power Expense $— $35 $35  $— $(30) $(30)
Regulatory Assets (2)
  (35) —  (35)  (405) —  (405)
              
 $(35) $35 $—  $(405) $(30) $(435)
              
  
Realized Gain (Loss) Reclassified to:  
Purchased Power Expense $— $(31) $(31) $— $(86) $(86)
Regulatory Assets (2)
  (68) —  (68)  (209) 9  (200)
              
 $(68) $(31) $(99) $(209) $(77) $(286)
              
  
2009
  
Unrealized Gain (Loss) Recognized in:  
Fuel Expense (1)
 $— 2 $2  $— $2 $2 
Regulatory Assets (2)
  (156) $—  (156)  (406) —  (406)
              
 $(156) $2 $(154) $(406) $2 $(404)
              
  
Realized Gain (Loss) Reclassified to:  
Fuel Expense (1)
 $— $— $—  $— $— $— 
Regulatory Assets (2)
  (96) —  (96)  (273) 11  (262)
              
 $(96) $— $(96) $(273) $11 $(262)
              
             
  Six Months Ended June 30, 
  NUG       
Derivatives Not in Hedging Relationships Contracts  Other  Total 
  (In millions) 
2010
            
Unrealized Gain (Loss) Recognized in:            
Purchased Power Expense $—  $(17) $(17)
Regulatory Assets (2)
  (259)  —   (259)
          
  $(259) $(17) $(276)
          
             
Realized Gain (Loss) Reclassified to:            
Purchased Power Expense $—  $(56) $(56)
Regulatory Assets (2)
  (146)  9   (137)
          
  $(146) $(47) $(193)
          
             
2009
            
Unrealized Gain (Loss) Recognized in:            
Fuel Expense (1)
 $—  $2  $2 
Regulatory Assets (2)
  (383)  —   (383)
          
   (383) $2  $(381)
          
Realized Gain (Loss) Reclassified to:            
Fuel Expense (1)
 $—  $(1) $(1)
Regulatory Assets (2)
  (179)  10   (169)
          
  $(179) $9  $(170)
          
(1) The realized gain (loss) is reclassified upon termination of the derivative instrument.
 
(2) Changes in the fair value of NUG contracts are deferred for future recovery from (or refund to) customers.
Total unamortized losses included in AOCL associated with commodity derivatives were $11$8 million ($75 million net of tax) as of JuneSeptember 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 $10$14 million increase related to current hedging activity and a $12$10 million decrease due to net hedge losses reclassified to earnings during the first sixnine months of 2010. Based on current estimates, approximately $10$7 million (net of tax) of the net deferred losses on derivative instruments in AOCL as of JuneSeptember 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 fluctuatefluctuates from period to period based on various market factors.

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Many of FirstEnergy’s commodity derivatives contain credit risk features. As of JuneSeptember 30, 2010, FirstEnergy posted $194$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 JuneSeptember 30, 2010 was $177$158 million, for which $194$192 million in collateral has been posted. If FirstEnergy’s credit rating were to fall below investment grade, it would be required to post $37$22.5 million of additional collateral related to commodity derivatives.

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5.6. 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 JuneSeptember 30, 2010 and 2009 was $21$20 million and $38$36 million, respectively. FirstEnergy’s net pension and OPEB expense for the sixnine months ended JuneSeptember 30, 2010 and 2009 was $45$65 million and $80$117 million, respectively. The components of FirstEnergy’s net pension and other postretirement benefit costs (including amounts capitalized) for the three and sixnine months ended June,September 30, 2010 and 2009, consisted of the following:
                                
 Three Months Ended Six Months Ended  Three Months Ended Nine Months Ended 
 June 30 June 30  September September 30 
Pension Benefits 2010 2009 2010 2009 
Pension Benefit Cost (Credit) 2010 2009 2010 2009 
 (In millions)  (In millions) 
Service cost $25 $22 $49 $43  $25 $23 $74 $66 
Interest cost 79 80 157 159  79 79 236 239 
Expected return on plan assets  (90)  (81)  (181)  (162)  (90)  (86)  (271)  (248)
Amortization of prior service cost 3 3 6 7  3 3 10 10 
Recognized net actuarial loss 47 42 94 85  47 45 141 129 
                  
Net periodic cost $64 $66 $125 $132  $64 $64 $190 $196 
                  
                                
 Three Months Ended Six Months Ended  Three Months Ended Nine Months Ended 
 June 30 June 30  September 30 September 30 
Other Postretirement Benefits 2010 2009 2010 2009 
Other Postretirement Benefit Cost (Credit) 2010 2009 2010 2009 
 (In millions)  (In millions) 
Service cost $3 $4 $5 $8  $2 $15 $7 $23 
Interest cost 11 18 22 38  11 13 33 51 
Expected return on plan assets  (9)  (9)  (18)  (18)  (9)  (9)  (27)  (27)
Amortization of prior service cost  (48)  (41)  (96)  (79)  (48)  (48)  (144)  (127)
Recognized net actuarial loss 15 15 30 31  15 15 45 46 
                  
Net periodic cost $(28) $(13) $(57) $(20) $(29) $(14) $(86) $(34)
                  

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Pension and other postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. The net periodic pension costs and net periodic other postretirement benefit costs (including amounts capitalized) recognized by FirstEnergy’s subsidiaries for the three and sixnine months ended JuneSeptember 30, 2010 and 2009 were as follows:
                                
 Three Months Ended Six Months Ended  Three Months Ended Nine Months Ended 
 June 30 June 30  September 30 September 30 
Pension Benefit Cost (Credit) 2010 2009 2010 2009 
Pension Benefit Cost 2010 2009 2010 2009 
 (In millions)  (In millions) 
FES $22 $18 $44 $36  $22 $19 $66 $56 
OE 6 7 11 14  6 6 17 20 
CEI 5 5 11 10  5 5 16 14 
TE 2 2 4 3  2 2 5 5 
JCP&L 6 9 12 18  6 8 19 26 
Met-Ed 3 6 5 11  3 5 8 16 
Penelec 5 4 9 9  5 4 14 13 
Other FirstEnergy Subsidiaries 15 15 29 31  15 15 45 46 
                  
 $64 $66 $125 $132  $64 $64 $190 $196 
                  

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 Three Months Ended Six Months Ended  Three Months Ended Nine Months Ended 
 June 30 June 30  September 30 September 30 
Other Postretirement Benefit Cost (Credit) 2010 2009 2010 2009  2010 2009 2010 2009 
 (In millions)  (In millions) 
FES $(7) $(3) $(13) $(4) $(7) $(4) $(20) $(8)
OE  (6)  (3)  (12)  (5)  (6)  (3)  (19)  (8)
CEI  (1) —  (3) 1   (1) —  (4) 1 
TE — —  (1) 1  — 1  (1) 2 
JCP&L  (2)  (1)  (4)  (2)  (2)  (2)  (5)  (4)
Met-Ed  (2)  (1)  (4)  (2)  (2)  (1)  (6)  (3)
Penelec  (2)  (1)  (4)  (2)  (2)  (1)  (6)  (2)
Other FirstEnergy Subsidiaries  (8)  (4)  (16)  (7)  (9)  (4)  (25)  (12)
                  
 $(28) $(13) $(57) $(20) $(29) $(14) $(86) $(34)
                  
6.7. 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.
FirstEnergy’s consolidated financial statements include the accounts of entities in which it has a controlling financial interest. FirstEnergy and its subsidiaries reflect the portion of VIEs not owned by them in the caption noncontrolling interest within the consolidated financial statements. The change in noncontrolling interest within the consolidated balance sheets is the result of net losses of the noncontrolling interests ($15 million) and distributions to owners ($4 million) for the six months ended June 30, 2010.
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 $326 million was outstanding as of June 30, 2010.

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In order to evaluate contracts under the consolidation guidance, FirstEnergy aggregated contracts into two categories based on similar risk characteristics and significance as follows:
Power Purchase Agreements
FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities may be VIEs to the extent they own a plant that sells substantially all of its output to the Utilities and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed and Penelec, maintains 21 long-term power purchase agreements with NUG entities. The agreements were entered into pursuant to the Public Utility Regulatory Policies Act of 1978. FirstEnergy was not involved in the 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 $53$73 million and $48$58 million for the three months ended JuneSeptember 30, 2010, and 2009, respectively and $117$190 million and $115$173 million for the sixnine months ended JuneSeptember 30, 2010 and 2009, respectively.

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Loss Contingencies
FirstEnergy has variable interests in certain sale-leaseback transactions. FirstEnergy concluded that it 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:above as of September 30, 2010:
                        
 Maximum Discounted Lease Net  Maximum Discounted Lease Net 
 Exposure Payments, net(1) Exposure  Exposure Payments, net(1) Exposure 
 (In millions)  (In millions) 
FES $1,352 $1,165 $187  $1,376 $1,185 $191 
OE 693 499 194  672 511 161 
CEI(2)
 662 70 592  627 71 556 
TE(2)
 662 339 323  627 346 281 
(1) The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is $1.6$1.7 billion.
 
(2) CEI and TE are jointly and severally liable for the maximum loss amounts under certain sale-leaseback agreements.
7.8. 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 as well as reachingand a settlement on an unrelated state tax matter in the secondthird 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 $70$78 million of net tax benefits, including $13$21 million that favorably affected FirstEnergy’s effective tax rate for the second quarterfirst nine months of 2010. The remaining portion of the tax benefit recognized in the first six months of 2010 increased FirstEnergy’s accumulated deferred income taxes for the settled temporary tax item.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 secondthird quarter of 2009.
As of JuneSeptember 30, 2010, it is reasonably possible that approximately $11$44 million of the unrecognized benefits may be resolved within the next twelve months, of which approximately $11less 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 recognized onfrom the disposition of assets and various otherthe 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 items.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 $11$13 million in the first sixnine months of 2010. During the first sixnine months of 2009, there were no material changes to the amount of interest accrued. The net amount of accumulated interest accrued as of JuneSeptember 30, 2010 was $6 million, as compared to $21 million as of December 31, 2009.

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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. AllTax returns for all state jurisdictions are open from 2001-2008.2006-2009. 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 was completed the audit in the first quarter of 2009 with two items under appeal. In the second quarter of 2010, the itemsItems under appeal for tax years 2006 and 2007 were settled and sent to Joint Committee on Taxation for final review.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.
8.9. 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 JuneSeptember 30, 2010, outstanding guarantees and other assurances aggregated approximately $3.9$3.8 billion, consisting primarily of parental guarantees ($0.90.8 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 $0.9$0.8 billion discussed above) as of JuneSeptember 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 aan LOC or accelerated payments may be required of the subsidiary. As of JuneSeptember 30, 2010, FirstEnergy’s maximum exposure under these collateral provisions was $451$419 million consisting of $37$374 million due to “material adverse event” contractual clauses, $83a below investment grade credit rating, of which $175 million is due to an acceleration of payment or funding obligation, and $331$45 million due to a below investment grade credit rating.“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 $609$511 million consisting of $56$463 million due to “material adverse event” contractual clauses, $83a below investment grade credit rating, of which $175 million is related to an acceleration of payment or funding obligation, and $470$48 million due to a below investment grade credit rating.“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 $90$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.

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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 JuneSeptember 30, 2010, and forward prices as of that date, FES has posted collateral of $245$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 $107$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 SO2SO2 and NOXNOX emissions regulations under the CAA. FirstEnergy complies with SO2 and NOx reduction requirements under the CAA and State Implementation Plan(s)SIP(s) under the CAA (SIPs) by burning lower-sulfur fuel, combustion controls and post-combustion controls, generating more electricity from lower-emitting plants and/or using emission allowances. Violations 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 in the U.S. District Court for the Western District of Pennsylvania also 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 ReliantRRI Energy, Inc. (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU and Met-Ed. Specifically, these suits allege that “modifications” at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR or permitting underin violation of the CAA’s PSD program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. 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.

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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 underin violation of the CAA’s PSD program. In May 2010, the EPA issued a second NOV to Mission Energy Westside, Inc., Penelec, NYSEGNew 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 scheduled 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 NOXNOX and SO2 emissions in two phases (2009/2010 and 2015), ultimately capping SO2 emissions in affected states to 2.5 million tons annually and NOXNOX emissions to 1.3 million tons annually. In 2008, the U.S. Court of Appeals for the District of Columbia vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” In December 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s opinion. The Court ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOX“NOX SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the “8-hour” ozone NAAQS. In July 2010, the EPA proposed the Clean Air Transport Rule (CATR) to replace CAIR, which remains in effect until the EPA finalizes CATR. CATR requires reductions of NOXNOX and SO2 emissions in two phases (2012 and 2014), ultimately capping SO2 emissions in affected states to 2.6 million tons annually and NOXNOX emissions to 1.3 million tons annually. The EPA proposed a preferred regulatory approach that allows trading of NOXNOX and SO2 emission allowances between power plants located in the same state with severeand severely limits on interstate trading of NOx and SO2 emission allowances. The EPA also requested comment on two alternative approaches—the first eliminates interstate trading of NOXNOX and SO2 emission allowances and the second eliminates trading of NOXNOX and SO2 emission allowances in its entirety. Depending on the actions taken by the EPA with respect to CATR, the proposed MACT regulations discussed below and any future regulations that are ultimately implemented, FGCO’s future cost of compliance may be substantial. Management is currently assessing the impact of these environmental proposals and other factors on FGCO’s facilities, particularly on the operation of its smaller, non-supercritical units. For example, as disclosed herein, management may decidedecided to idle certain of these 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. The EPA entered into a consent decree requiring it to propose maximum achievable control technology (MACT) regulations for mercury and other hazardous air pollutants by March 16, 2011, and to finalize the regulations by November 16, 2011. On April 29, 2010, the EPA issued proposed MACTmaximum 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.
Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap-and-trade approach as in the CAMR, but rather follows a command-and-control approach imposing emission limits on individual sources. On December 23, 2009, the Supreme Court of Pennsylvania affirmed the Commonwealth Court of Pennsylvania ruling that Pennsylvania’s mercury rule is “unlawful, invalid and unenforceable” and enjoined the Commonwealth from continued implementation or enforcement of that rule.

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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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The EPA has authority under the CAA to regulate “air pollutants” from electric generating plants and other facilities.
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 GHGGHGs increase the threat of climate change.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 willwould 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 CAACAA’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 Prevention of Significant Determination (PSD)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, includedCelsius; 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 2020,2020; and establishedestablish 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,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, should the court of appeals decision be affirmed or not subjected to further review, FirstEnergy and/or one or more of its subsidiaries could be named in actions making similar allegations.
FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO2 emissions per KWH of electricity generated by FirstEnergy is lower than many regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy’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

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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 JuneSeptember 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 JuneSeptember 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. Early in 2010, the Appellate Division heard oral argument on plaintiff’s appeal of the trial court’s decision decertifying the class, and onOn 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 15)16), purported shareholders of Allegheny Energy have filed putative shareholder class action and/or derivative lawsuits in Pennsylvania and Maryland state courts, as well as in the U.S. District Court for the Western District of Pennsylvania, against Allegheny Energy and its directors and certain officers, referred to as the Allegheny Energy defendants, FirstEnergy and Merger Sub. 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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agreement, and that Allegheny Energy, FirstEnergy and Merger Sub aided and abetted in these alleged breaches of fiduciary duty. The complaints seek, among other things, jury trials, money damages and injunctive relief. Additional details about the actions are provided below. While FirstEnergy believes the lawsuits are without merit and has defended vigorously against the claims, in order to avoid the costs associated with the litigation, the defendants have agreed to the terms of a disclosure-based settlement of the lawsuits. The defendantsall these shareholder lawsuits and have reached an agreement with counsel for all of the plaintiffs concerning fee applications, but aapplications. Under the terms of the settlement, no payments are being made by FirstEnergy or Merger Sub. A formal stipulation of settlement has not yet beenwas filed with any court.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.
Four putative class action and derivative lawsuits were filed in the Circuit Court for Baltimore City, Maryland. One was withdrawn. The court consolidated the three cases under the captionOakmont Capital Management, LLC v. Evanson, et al., C.A. No. 24-C-10-1301, and appointed Lewis M. Lynn as Lead Plaintiff. Plaintiff Lynn filed a Consolidated Amended Complaint on April 12, 2010. On April 21, 2010, defendants filed Motions to Dismiss the Consolidated Amended Complaint for failure to state a claim. The court has stayed all discovery pending resolution of those motions. The court also has entered a stipulated order certifying a class with no opt-out rights. On May 27, 2010, the parties reported to the court that they have agreed to the terms of a disclosure-based settlement and requested that the court cancel the oral argument on the motions to dismiss that had been scheduled for June 3, 2010. On May 28, 2010, the court removed the hearing from its calendar.
Three shareholder lawsuits were filed in the Court of Common Pleas of Westmoreland County, Pennsylvania, raising putative class action and derivative claims against the Allegheny Energy directors and officers, FirstEnergy and Allegheny Energy. The court has consolidated these actions under the caption,In re Allegheny Energy, Inc. Shareholder Class and Derivative, Litigation, Lead Case No. 1101 of 2010, and appointed lead counsel. On April 5, 2010, the Allegheny Energy defendants filed a Motion to Stay the Proceedings. Shortly thereafter, FirstEnergy similarly filed a Motion to Stay. Plaintiffs filed a Motion for Expedited Discovery. The court scheduled a hearing on the motions for May 27, 2010. On May 21, 2010, plaintiffs filed a Verified Consolidated Shareholder Derivative and Class Complaint. On May 26, 2010, the parties filed a Motion for a Continuance of the May 27 hearing, which the court granted. On June 1, 2010, the parties reported to the court that they have agreed to the terms of a disclosure-based settlement.
A putative shareholder lawsuit styled as a class action was filed in the U.S. District Court for the Western District of Pennsylvania and is captionedLouisiana Municipal Police Employees’ Retirement System v. Evanson, et al., C.A. No. 10-319 NBF. On June 1, 2010, the parties reported to the court that they have agreed to the terms of a disclosure-based settlement.
Nuclear Plant Matters
During a planned refueling outage that began on February 28, 2010, FENOC conducted a non destructive examination and testing of the Control Rod Drive Mechanism (CRDM) Nozzlesnozzles 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 JuneSeptember 30, 2010, FirstEnergy had approximately $1.9$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. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy providedprovides an additional $80$15 million parental guarantee associated with the funding of decommissioning costs for these units and indicated that it planned to contribute an additional $80 million to these trusts by 2010. By a letter dated March 8, 2010, primarily as a result of the Beaver Valley Power Station operating license renewal, FENOC requested that the NRC reduce FirstEnergy’s parental guarantee to $15 million and notified the staff that it no longer planned to make the additional contributions into the trusts. By a letter dated July 14, 2010, the NRC stated that it had no objection to the reduction in the parental guarantee.units.

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Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.
On April 14, 2010, JCP&L reached an agreement on a settlement package with its bargaining unit employees regarding a grievance challenging JCP&L’s 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. The agreement included an agreed-upon settlement amount and extension of the collective bargaining agreement. On July 22, 2010, the court signed an order approving and implementing the parties’ agreement. As of June 30, 2010, JCP&L reduced its reserve to $9 million for the settlement which will be paid to the employees over the next thirty days beginning on July 25, 2010. The collective bargaining agreement extension is also effective as of July 25, 2010.
On February 16, 2010, a class action lawsuit was filed in Geauga County Court of Common Pleas against FirstEnergy, CEI and OE seeking declaratory judgment and injunctive relief, as well as compensatory, incidental and consequential damages, on behalf of a class of customers related to the 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 has not yet ruled on thatgranted the motion to dismiss. The named-defendant companies will continue to defend these claims including challenging any class certification.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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9.10. 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 ReliabilityFirstCorporation. All of FirstEnergy’s facilities are located within the ReliabilityFirstregion. FirstEnergy actively participates in the NERC and ReliabilityFirststakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by the ReliabilityFirstCorporation.
FirstEnergy believes that it generally is in compliance with all currently-effective and enforceable reliability standards. Nevertheless,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, ReliabilityFirstand the FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with new or amended standards cannot be determined at this time; however, 2005 amendments to the FPA provide that all prudent costs incurred to comply with the new reliability standards be recovered in rates. Still, any future inability on FirstEnergy’s part to comply with the reliability standards for its bulk power system could result in the imposition of financial penalties that could have a material adverse effect on its financial condition, results of operations and cash flows.
On December 9, 2008, a transformer at JCP&L’s Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission voltage) lines out of the Oceanview and Atlantic substations resulting in customers losing power for up to eleven hours. On March 31, 2009, the NERC initiated a Compliance Violation Investigation in order to determine JCP&L’s contribution to the electrical event and to review any potential violation of NERC Reliability Standards associated with the event. NERC has submitted first and second Requests for Information regarding this and another related matter. JCP&L is complying with these requests. JCP&L is not able to predict what actions, if any, that the NERC may take with respect to this matter.

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On August 23, 2010, FirstEnergy self-reported 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, ReliabilityFirstissued a Notice of Enforcement to investigate the incident. FirstEnergy submitted a data response to ReliabilityFirston 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). As one element of the Amended ESP, the Ohio Companies agreed not to seek an additional base distribution rate increase, subject to certain exceptions, that would be effective before January 1, 2012. Applications for rehearing of the PUCO 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. A technical conference and hearings were held in 2009 and the matter has been fully briefed. Pursuant to SB221, the PUCO has 90 days from the date of the application to determine whether the MRO meets certain statutory requirements. Although the Ohio Companies requested a PUCO determination by January 18, 2010, on February 3, 2010, the PUCO announced that its determination would be delayed. Under a determination that such statutory requirements are met, and to the extent the ESP described belowThe PUCO has not been implemented, the Ohio Companies would expect to implement the MRO.yet issued an order in this matter.
On March 23, 2010, the Ohio Companies filed an application for a new ESP. The new ESP which if approved by the PUCO, wouldwill 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;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.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. The evidentiary hearing began on April 20, 2010, at the PUCO. The Stipulation requested a decision by the PUCO by May 5, 2010. On April 28, 2010, the PUCO Chairman issued a statement that the PUCO would not issue a decision on May 5, 2010, and would take additional time to review the case record. FirstEnergy recorded approximately $39.5 million of regulatory asset impairments and expenses related to the ESP. On May 12, 2010, a supplemental stipulation was filed that added two additional parties to the Stipulation, namely the City of Akron, Ohio and Council for Smaller Enterprises, to provide additional energy efficiency benefits. Pursuant to a PUCO Entry, a hearing was held on June 21, 2010 to consider the estimated bill impacts arising from the proposed ESP, and testimony was provided in support of the supplemental stipulation. On July 22, 2010, a second supplemental stipulation was filed that, among other provisions and if approved, would provideprovides a commitment that retail customers of the Ohio Companies will not pay certain costs related to the companies’ integration into PJM, a regional transmission organization, for the longer of the five year period from June 1, 2011 through May 31, 2016 or when the amount of costs avoided by customers for certain types of products totals $360 million 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. A hearingThe 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 heldfiled 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 second supplemental stipulation on July 29, 2010. The matter is awaiting decision fromsubstance of the PUCO.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 PUCO may amend these benchmarks in certain, limited circumstances, and the Ohio Companies filed an application with the PUCO seeking such amendments.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 CompaniesCompanies’ 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 serveserved in 2009. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RFPs sought RECs, including solar RECs and RECs generated in Ohio in order to meet the Ohio Companies’ alternative energy requirements as set forth in SB221 for 2009, 2010 and 2011. The RECs acquired through these two RFPs will bewere 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’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. OnIn July 1, 2010, the Ohio Companies announced their intent to conductinitiated an additional RFP in 2010 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, bids are duecontracts were executed in August 3, 2010 and contracts are expected to be signed the week of August 9, 2010.
On February 12, 2010, OE and CEI filed an application with the PUCO to establish a new credit for all-electric customers. On March 3, 2010, the PUCO ordered that rates for the affected customers be set at a level that will provide bill impacts commensurate with charges in place on December 31, 2008 and authorized the Ohio Companies to defer incurred costs equivalent to the difference between what the affected customers would have paid under previously existing rates and what they pay with the new credit in place. Tariffs implementing this new credit went into effect on March 17, 2010. On April 15, 2010, the PUCO issued a Second Entry on Rehearing that expanded the group of customers to which the new credit would apply and authorized deferral for the associated additional amounts. The PUCO also stated that 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. No hearing has been scheduled in this matter.
As noted above in Note 8, FirstEnergy, CEI and OEOn September 9, 2010, the OCC filed a motion to dismissrequesting that a class action lawsuitprocedural schedule be established. The Ohio Companies filed their motion contra on September 23, 2010. The PUCO Staff issued a report related to the PUCO approved reductionall-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 discount that had previously been in place for residential customers with electric heating, electric water heating, or load management systems. The court has not yet ruled on that motionlonger term solution, but it made no specific recommendation to dismiss.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. TheOn July 29, 2010, the parties to the proceeding have reachedfiled a settlementJoint 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 filed a joint petitionretail market issues. The PPUC’s approval of the Joint Petition is conditioned by holding that the provision relating to approve the settlement agreement in July 2010. The PPUC is requiredrecovery 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 issue an order on the plan no later than November 8, 2010. Ifapproval of cost recovery by FERC. Penn may not put these provisions into effect until FERC has approved procurement under the planrecovery and allocation of MISO exit fees and PJM integration costs. An Order consistent with the Motion is expected to begin January 2011.be entered in the near future.

49

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 loss costs.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 April 2, 2010, Met-Ed and Penelec filed a Response to the PPUC’s March 3, 2010 Order requesting approval of procedures to establish separate accounts to track all marginal transmission loss revenues and related interest and the use of those funds to mitigate future generation rate increases commencing January 1, 2011, and the PPUC entered an Order on June 7, 2010, granting Met-Ed’s and Penelec’s request. On July 9, 2010, Met-Ed and Penelec filed their briefs with the Commonwealth Court of Pennsylvania. The Office of Small Business Advocate filed its brief on July 9, 2010. The PPUC’sOn August 24, 2010, the PPUC as well as MEIUG and PICA filed their briefs. Met-Ed and Penelec filed their reply brief is due to be filed in Auguston 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 be fully recoveredprovide 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.

48

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 rollinclude smart meter costs intoin base rates.
Legislation addressing rate mitigation 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 the expiration of rate caps was introducedPenn from seeking to include smart meter costs in the legislative session that ended in 2008; several bills addressing these issues were introduced in the 2009 legislative session. The final form and impact of such legislation is uncertain.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.

50

(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 JuneSeptember 30, 2010, the accumulated deferred cost balance totaledwas a credit of approximately $81$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.

49

(E) FERC MATTERS
PJM Transmission Rate
On April 19, 2007, the FERC issued an order (Opinion 494) finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate based on the amount of load served in a transmission zone. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a load flow methodology referred to as “DFAX”(DFAX), which is generally referred to as a “beneficiary pays” approach to allocating the cost of high voltage transmission facilities. The FERC found that PJM’s current beneficiary-pays cost allocation methodology was not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff. FERC ultimately issued an order approving use of the beneficiary pays method of cost allocation for transmission facilities included in the PJM regional plan that operate below 500 kV.
The FERC’s April 19, 2007Opinion 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.

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In an order dated January 21, 2010, FERC set the matter for “paper hearings”—meaning that FERC called for parties to submit comments or written testimony pursuant to the schedule described in the order. FERC identified nine separate issues for comments and directed PJM to file the first round of comments on February 22, 2010, with other parties submitting responsive comments within 45 days, and the reply comments 30 days later.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 not expected to act before the fourth quarterend of 2010.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. Most of FirstEnergy’s transmission assets in Pennsylvania and all ofIn the transmission assets in New Jersey already operate as a part of PJM.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.
InOn 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, and the Ohio Companies and Penn’s loadPenn to movingthe move into PJM on the schedule described in the application and approved in the FERC Order.PJM.
FirstEnergy successfully conducted the FRR auctions on March 19, and2010. Moreover, the ATSI-zone loads participated in the PJM base residual auction for the 2013 delivery year, thereby obtainingyear. Successful completion of these steps secured the capacity necessary for itsthe ATSI footprint to meet PJM’s capacity requirements. FirstEnergy expects to integrate into PJM effective June 1, 2011.
On September 4, 2009, the PUCO opened a case to take comments from Ohio’s stakeholders regarding the RTO consolidation. Several parties have intervened inOn August 25, 2010, the regulatory dockets at the FERC and at the PUCO. Certain interveners have commented and protested particular elements of the proposed RTO consolidation, including an exit fee to MISO, integration costs to PJM, and cost-allocations of future transmission upgrades in PJM and MISO.
MISO Complaints Versus PJM
On March 9, 2010, MISO filed two complaints against PJM with FERC under Sections 206, 306 and 309 of the FPA alleging violations of the MISO/PJM Joint Operating Agreement (JOA). In Docket EL 10-46-000, the complaint alleges that PJM erroneously calculated charges to MISO for market-to-market settlements made from 2005 to 2009 pursuant to the congestion management provisions of the JOA. The MISO seeks approximately $130 million plus interest to correct for resultant net underpayments from PJM to MISO. In Docket No.EL10-45-000, MISO alleges that by failing to account for the market flows from 34 PJM generators over the period from 2007-2009, PJM underpaid MISO by a total of roughly $75 million including interest. For the period from 2005-2007, MISO claimed an underpayment by PJM of at least $12 million plus interest. MISO also claimed that PJM failed to maintain required records necessary to calculate underbilling for the 2005-2007 billing.
In the second complaint, MISO alleged that PJM has refused to comply with provisions of the JOA requiring market-to-market dispatch since 2009, and is improperly demanding repayment of redispatch payments previously made to MISO. PJM filed its answers to the complaints on April 12, 2010, opposing the relief sought by MISO.
In addition, on April 12, 2010, PJM filed a complaint with FERC pursuant to Section 206, 306, and 309 alleging that MISO is violating the JOA with PJM by initiating market-to-market coordination and financial settlements for substitute (proxy) reciprocal coordinated flowgates between MISO and PJM. PJM claims that the JOA does not permit MISO to initiate market-to-market settlements using proxy flowgates in lieu of designated reciprocal coordinated flowgates. This complaint addresses substantially the same issues as the second MISO complaint, in which MISO argues that the use of proxy flowgates is permitted by agreement of the RTOs and operating practice. Each party filed a complaint in order to ensure their right to claim refunds, if any, if successful in their arguments at FERC.
On June 29, 2010, FERCPUCO issued an order consolidatingthat, among other things, committed the casesPUCO to close this case and establishing settlement judge procedures. Ifalso to withdraw its objections that were filed in the settlement process is unsuccessful,relevant FERC dockets conditioned upon the casesOhio 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 proceedbe resolved in future FERC proceedings. Under the terms of the ESP order issued on August 25, 2010, the PUCO has agreed to evidentiary hearings. FirstEnergy is unable to predict the outcome ofclose this matter.docket.

52

MISO Multi-Value Project Rule Proposal
On July 15, 2010, MISO and certain MISO transmission owners jointly filed with the FERC their proposed cost allocation methodology for new transmission projects. If approved, so-called Multi ValueThe new transmission projects—described as Multi-Value Projects (MVPs)— transmission projects that haveare a regional impact and are partclass of MTEP projects. The MISO proposes to allocate the costs of MVPs by means of a regional plan —usage-based charge that will have a 100% regional allocationbe 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 costs under the proposed methodology. If approved by FERC, MISO’sMISO. MISO expects that its MVP proposal is expected to permit the allocation ofwill fund the costs of large transmission projects designed to integratebring wind generation from the upper Midwest acrossto load centers in the entire MISO.east. MISO has requested athat FERC response to the filingrule on its MVP proposal by the FERC’s December, open meeting, 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.

50

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.
10.11. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
In 2010, the FASB amended the Derivatives and HedgingReceivable Topic of the FASB Accounting Standards Codification to clarifyenhance disclosures about the scope exceptioncredit quality of financing receivables and the allowance for embedded credit derivative features relatedlosses. The update amends existing disclosures to require an entity to provide a greater level of disaggregated information about the transfercredit quality of its financing receivables and its allowance for credit risk in the form of subordination of one financial instrument to another.losses. The amendment addresses howalso requires an entity to determine which embeddeddisclose credit derivative features, including those in collateralized debt obligationsquality indicators, past due information, and synthetic collateralized debt obligations, are considered to be embedded derivatives that should not be analyzed under the Derivatives and Hedging Topic for potential bifurcation and separate accounting.modifications of its financing receivables. The amendment is effective for the first fiscal quarter beginninginterim and annual reporting periods ending on or after JuneDecember 15, 2010. FirstEnergy does not expectis currently evaluating the impact of adopting this standard to have a material effect on its financial statements.
11.12. 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 Michigan.New Jersey. This business segment owns or leases and operates 19 generating facilities with a net demonstratedcontrols approximately 14,000 MW of capacity of 13,710 MWs and also purchases electricity to meet sales obligations. The segment’s net income is primarily derived from affiliated and non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO to deliver energy to the segment’s customers.
The other segment contains corporate items and other businesses that are below the quantifiable threshold for separate disclosure as a reportable segment.

 

5351

                     
  Energy  Competitive           
  Delivery  Energy      Reconciling    
Segment Financial Information Services  Services  Other  Adjustments  Consolidated 
  (In millions) 
                     
Three Months Ended
                    
                     
June 30, 2010
                    
External revenues $2,373  $778  $6  $(29) $3,128 
Internal revenues  19   539   —   (558)  — 
                
Total revenues  2,392   1,317   6   (587)  3,128 
Depreciation and amortization  276   66   6   3   351 
Investment income (loss), net  27   13   —   (9)  31 
Net interest charges  123   31   3   10   167 
Income taxes  89   76   (22)  (9)  134 
Net income (loss)  143   125   16   (28)  256 
Total assets  22,450   11,100   591   325   34,466 
Total goodwill  5,551   24   —   —   5,575 
Property additions  172   282   7   28   489 
                     
June 30, 2009
                    
External revenues $2,792  $504  $5  $(30) $3,271 
Internal revenues  —   839   —   (839)  — 
                
Total revenues  2,792   1,343   5   (869)  3,271 
Depreciation and amortization  298   68   3   4   373 
Investment income (loss), net  35   6   —   (14)  27 
Net interest charges  113   18   2   40   173 
Income taxes  103   185   (20)  (20)  248 
Net income  154   276   18   (40)  408 
Total assets  23,215   10,144   684   263   34,306 
Total goodwill  5,551   24   —   —   5,575 
Property additions  178   248   70   (7)  489 
                     
Six Months Ended
                    
                     
June 30, 2010
                    
External revenues $4,916  $1,494  $10  $(60) $6,360 
Internal revenues*  19   1,213   —   (1,165)  67 
                
Total revenues  4,935   2,707   10   (1,225)  6,427 
Depreciation and amortization  601   132   19   4   756 
Investment income (loss), net  52   14   —   (19)  47 
Net interest charges  246   64   2   27   339 
Income taxes  158   123   (18)  (18)  245 
Net income (loss)  257   201   1   (54)  405 
Total assets  22,450   11,100   591   325   34,466 
Total goodwill  5,551   24   —   —   5,575 
Property additions  338   605   10   44   997 
                     
June 30, 2009
                    
External revenues $5,813  $839�� $12  $(59) $6,605 
Internal revenues  —   1,732   —   (1,732)  — 
                
Total revenues  5,813   2,571   12   (1,791)  6,605 
Depreciation and amortization  725   132   4   7   868 
Investment income (loss), net  65   (23)  —   (26)  16 
Net interest charges  222   36   3   78   339 
Income taxes  91   288   (37)  (40)  302 
Net income  136   431   35   (79)  523 
Total assets  23,215   10,144   684   263   34,306 
Total goodwill  5,551   24   —   —   5,575 
Property additions  343   669   119   12   1,143 
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.

 

5452

12.13. 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 sixnine month periods ended JuneSeptember 30, 2010 and 2009, consolidating balance sheets as of JuneSeptember 30, 2010 and December 31, 2009 and consolidating statements of cash flows for the sixnine months ended JuneSeptember 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.

 

53

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)
                

54

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 
                

55

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
                                        
For the Three Months Ended June 30, 2010 FES FGCO NGC Eliminations Consolidated 
For the Three Months Ended September 30, 2009 FES FGCO NGC Eliminations Consolidated 
 (In thousands)  (In thousands) 
  
REVENUES
 $1,295,700 $580,621 $338,933 $(900,580) $1,314,674  $1,087,991 $477,679 $170,129 $(631,227) $1,104,572 
                      
  
EXPENSES:
  
Fuel 7,268 300,867 34,276 — 342,411  9,278 241,953 43,462 — 294,693 
Purchased power from affiliates 912,858 7,163 49,457  (900,580) 68,898  621,996 9,233 35,290  (631,229) 35,290 
Purchased power from non-affiliates 298,820 — — — 298,820  205,200 — — — 205,200 
Other operating expenses 80,983 94,373 116,350 12,189 303,895  70,246 109,828 113,669 12,192 305,935 
Provision for depreciation 711 27,466 36,449  (1,307) 63,319  1,051 30,469 35,832  (1,311) 66,041 
General taxes 5,718 9,227 7,327 — 22,272  4,351 11,331 6,018 — 21,700 
                      
Total expenses 1,306,358 439,096 243,859  (889,698) 1,099,615  912,122 402,814 234,271  (620,348) 928,859 
                      
  
OPERATING INCOME (LOSS)
  (10,658) 141,525 95,074  (10,882) 215,059 
OPERATING INCOME
 175,869 74,865  (64,142)  (10,879) 175,713 
                      
  
OTHER INCOME (EXPENSE):
  
Investment income 1,811 81 11,474 — 13,366  35 319 158,503 — 158,857 
Miscellaneous income (expense), including net income from equity investees 151,291 709 102  (147,709) 4,393  100,668 744 1  (98,609) 2,804 
Interest expense to affiliates  (61)  (2,084)  (415) —  (2,560)  (35)  (1,267)  (907) —  (2,209)
Interest expense — other  (24,262)  (27,799)  (15,361) 16,050  (51,372)  (15,358)  (26,737)  (16,205) 16,113  (42,187)
Capitalized interest 98 19,573 4,234 — 23,905  49 15,381 2,439 — 17,869 
                      
Total other income (expense) 128,877  (9,520) 34  (131,659)  (12,268) 85,359  (11,560) 143,831  (82,496) 135,134 
                      
  
INCOME BEFORE INCOME TAXES
 118,219 132,005 95,108  (142,541) 202,791  261,228 63,305 79,689  (93,375) 310,847 
  
INCOME TAXES (BENEFITS)
  (15,706) 48,465 33,550 2,557 68,866 
INCOME TAXES
 61,545 19,646 27,801 2,172 111,164 
                      
  
NET INCOME
 $133,925 $83,540 $61,558 $(145,098) $133,925  $199,683 $43,659 $51,888 $(95,547) $199,683 
                      

 

56

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
                                        
For the Six Months Ended June 30, 2010 FES FGCO NGC Eliminations Consolidated 
For the Nine Months Ended September 30, 2009 FES FGCO NGC Eliminations Consolidated 
 (In thousands)  (In thousands) 
  
REVENUES
 $2,662,725 $1,148,985 $765,253 $(1,874,196) $2,702,767  $3,357,873 $1,726,715 $955,452 $(2,368,210) $3,671,830 
                      
  
EXPENSES:
  
Fuel 12,365 581,730 76,537 — 670,632  16,400 755,632 99,128 — 871,160 
Purchased power from affiliates 1,881,395 12,242 110,410  (1,874,196) 129,851  2,351,879 16,333 149,746  (2,368,212) 149,746 
Purchased power from non-affiliates 749,035 — — — 749,035  551,155 — — — 551,155 
Other operating expenses 134,109 194,149 255,770 24,378 608,406  144,284 313,416 397,284 36,571 891,555 
Provision for depreciation 1,501 53,993 73,359  (2,616) 126,237  3,087 90,680 103,135  (3,940) 192,962 
General taxes 11,216 23,827 13,975 — 49,018  12,826 35,289 18,246 — 66,361 
                      
Total expenses 2,789,621 865,941 530,051  (1,852,434) 2,333,179  3,079,631 1,211,350 767,539  (2,335,581) 2,722,939 
                      
  
OPERATING INCOME (LOSS)
  (126,896) 283,044 235,202  (21,762) 369,588 
OPERATING INCOME
 278,242 515,365 187,913  (32,629) 948,891 
                      
  
OTHER INCOME (EXPENSE):
  
Investment income 3,708 135 10,240 — 14,083  83 758 134,882 — 135,723 
Miscellaneous income (expense), including net income from equity investees 317,664  (924) 1  (311,038) 5,703  509,927 1,209 15  (498,311) 12,840 
Interest expense to affiliates  (119)  (3,896)  (850) —  (4,865)  (103)  (4,648)  (3,752) —  (8,503)
Interest expense — other  (47,635)  (54,305)  (31,124) 32,048  (101,016)  (20,778)  (72,762)  (46,050) 48,605  (90,985)
Capitalized interest 198 35,906 7,491 — 43,595  146 34,257 7,572 — 41,975 
                      
Total other income (expense) 273,816  (23,084)  (14,242)  (278,990)  (42,500) 489,275  (41,186) 92,667  (449,706) 91,050 
                      
  
INCOME BEFORE INCOME TAXES
 146,920 259,960 220,960  (300,752) 327,088  767,517 474,179 280,580  (482,335) 1,039,941 
  
INCOME TAXES (BENEFITS)
  (66,931) 96,508 78,563 5,097 113,237 
INCOME TAXES
 99,751 166,902 98,893 6,629 372,175 
                      
  
NET INCOME
 $213,851 $163,452 $142,397 $(305,849) $213,851  $667,766 $307,277 $181,687 $(488,964) $667,766 
                      

 

57

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

 

58

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

 

59

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

 

60

FIRSTENERGY SOLUTIONS CORP.

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

61

FIRSTENERGY SOLUTIONS CORP.

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

62

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
                                        
For the Six Months Ended June 30, 2009 FES FGCO NGC Eliminations Consolidated 
For the Nine Months Ended September 30, 2009 FES FGCO NGC Eliminations Consolidated 
 (In thousands)  (In thousands) 
 
NET CASH PROVIDED FROM OPERATING ACTIVITIES
 $285,284 $314,041 $221,625 $(8,734) $812,216 
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— 
New Financing- 
Long-term debt — 347,710 333,965 — 681,675  1,498,087 524,710 333,965 — 2,356,762 
Short-term borrowings, net 98,880 — 128,716  (82,587) 145,009  — — — — — 
Redemptions and Repayments— — 
Equity contributions from parent — 100,000 150,000  (250,000) — 
Redemptions and Repayments- 
Long-term debt  (1,696)  (260,372)  (369,519) 8,734  (622,853)  (1,507)  (258,583)  (366,857) 8,734  (618,213)
Short-term borrowings, net —  (82,587) — 82,587 —   (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 97,184 4,751 93,162 8,734 203,831  583,878 103,509 107,601  (241,268) 553,720 
                      
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (694)  (332,789)  (301,484) —  (634,967)  (2,224)  (439,531)  (400,845) —  (842,600)
Proceeds from asset sales — 15,771 — — 15,771  — 16,129 — — 16,129 
Sales of investment securities held in trusts — — 537,078 — 537,078  — — 2,152,717 — 2,152,717 
Purchases of investment securities held in trusts — —  (550,730) —  (550,730) — —  (2,175,135) —  (2,175,135)
Loans to associated companies, net  (261,839) 20,669 — —  (241,170)  (27,054)  (178,746)  (93,041) —  (298,841)
Investment in subsidiary  (250,000) — — 250,000 — 
Other 65  (22,448) 349 —  (22,034) 249  (21,470) 339 —  (20,882)
                      
Net cash used for investing activities  (262,468)  (318,797)  (314,787) —  (896,052)  (279,029)  (623,618)  (515,965) 250,000  (1,168,612)
                      
  
Net change in cash and cash equivalents 120,000  (5) — — 119,995  266,859 60 — — 266,919 
Cash and cash equivalents at beginning of period — 39 — — 39  — 39 — — 39 
                      
Cash and cash equivalents at end of period $120,000 $34 $— $— $120,034  $266,859 $99 $— $— $266,958 
                      
13.14. 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 $118$127 million are included in other assets on FirstEnergy’s Consolidated Balance Sheet as of JuneSeptember 30, 2010.
For the three and sixnine months ended JuneSeptember 30, 2010, amortization expense was approximately $3$2 million and $5$6 million, respectively.
14. ASSET RETIREMENT OBLIGATIONS15. IMPAIRMENT OF LONG-LIVED ASSETS
FirstEnergy has recognized applicable legal obligationsreviews long-lived assets for AROs and their associated cost for nuclear power plant decommissioning, reclamationimpairment whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The recoverability of a sludge disposal pond and closure of two coal ash disposal sites. In addition, FirstEnergy has recognized conditionallong-lived asset retirement obligations (primarily for asbestos remediation).
The ARO liabilities for FES, OE and TE primarily relateis measured by comparing its carrying value to the decommissioningsum of undiscounted future cash flows expected to result from the use and eventual disposition of the Beaver Valley, Davis-Besseasset. If the carrying value is greater than the undiscounted cash flows, an impairment exists and Perry nuclear generating facilities (OEa loss is recognized for their leasehold interest in Beaver Valley Unit 2 and Perry and TE for its leasehold interest in Beaver Valley Unit 2). The ARO liabilities for JCP&L, Met-Ed and Penelec primarily relate to the decommissioningamount by which the carrying value of the TMI-2 nuclear generating facility. FES and the Utilities use an expected cash flow approach to measure thelong-lived asset exceeds its estimated fair value of their nuclear decommissioning AROs.value.
During the second quarter ending September 30, 2010, FirstEnergy announced its intention to make operational changes at certain coal-fired FGCO units. The announcement of 2010, studies were completedthe operational change indicated a need to reassessevaluate the estimated costfuture recoverability of decommissioning the Beaver Valley nuclear generating facility. The cost studies resulted in a revision tocarrying value of the estimated cash flowsassets associated with the ARO liabilitiesaffected FGCO units. As a result of FES, OEthe 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 TE and reduced the liability for each subsidiary in the amountsa charge of $88 million, $7 million and $5 million, respectively,for excessive or obsolete inventory identified as a result of June 30, 2010.
The revision to the estimated cash flows had no significant impact on accretion expense during the second quarter of 2010 when compared to the second quarter of 2009.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.
15.16. 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, and its wholly-owned subsidiary (Merger Sub) and Allegheny Energy, Inc., a Maryland corporation (Allegheny Energy). Upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will merge with 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, as well aswhich 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 the VSCC 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 $7$14 million ($511 million after tax) of merger transaction costs in the secondthird quarter and approximately $21$35 million ($1526 million after tax) of merger transaction costs in the first sixnine months of 2010. These costs are expensed as incurred.

 

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Item 2.
Item 2. Management’s Discussion and Analysis of Registrant and Subsidiaries
FIRSTENERGY CORP.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
EXECUTIVE SUMMARY
Earnings available to FirstEnergy in the secondthird quarter of 2010 were $265$179 million, or basic and diluted earnings of $0.87$0.59 per share of common stock, compared with $414$234 million, or basic and diluted earnings of $1.36$0.77 per share of common stock in the secondthird quarter of 2009. Results in the secondthird quarter of 2010 were adversely affected by the absence of a 2009 gain from the sale of a 9% participation interest in OVEC.an impairment charge for certain coal-fired generation units. Earnings available to FirstEnergy in the first sixnine months of 2010 were $420$599 million or basic earnings of $1.38$1.97 ($1.371.96 diluted) per share of common stock, compared with $533$768 million, or basic and diluted earnings of $1.75$2.52 per share of common stock ($2.51 diluted) in the first sixnine months of 2009.
        
         Three Months Nine Months 
 Three Months Six Months  Ended Ended 
Change in Basic Earnings Per Share From Prior Year Ended June 30 Ended June 30  September 30 September 30 
 
Basic Earnings Per Share — 2009 $1.36 $1.75  $0.77 $2.52 
Non-core asset sales/impairments  (0.52)  (0.54)  (0.60)  (1.14)
Trust securities impairments  (0.01) 0.04   (0.04) — 
Regulatory charges — 2009 — 0.55 
Regulatory charges — 2010 —  (0.08)
Regulatory charges  (0.02) 0.45 
Derivative mark-to-market adjustment — 2010 0.07  (0.04)  (0.03)  (0.07)
Organizational restructuring — 2009 0.01 0.06  0.08 0.14 
Merger transaction costs — 2010  (0.02)  (0.05)  (0.04)  (0.09)
Litigation settlements 0.04 0.04  — 0.04 
Debt call premium — 2009 0.01 0.01  0.30 0.31 
Income tax resolution — 2009 —  (0.04) —  (0.04)
Income tax charge from healthcare legislation — 2010 —  (0.04) —  (0.04)
Revenues 0.23 0.16  0.56 0.72 
Fuel and purchased power  (0.28)  (0.41)  (0.09)  (0.50)
Transmission expense  (0.08) 0.02   (0.18)  (0.16)
Amortization of regulatory assets, net 0.06  (0.11) 0.17 0.06 
Investment income 0.02 0.03   (0.26)  (0.23)
Other expenses  (0.02) 0.03   (0.03) — 
          
Basic Earnings Per Share — 2010 $0.87 $1.38  $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, and its wholly-owned subsidiary (Merger Sub) and Allegheny Energy, Inc., a Maryland corporation (Allegheny Energy). Upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will merge with 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 isremains conditioned upon, among other things, shareholder approval of both companies, the SEC’s clearance of a registration statement registering the FirstEnergy common stock to be issued in connection with the merger, as well as expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and approval by the FERC, the MDPSC, the PPUC the VSCC and the PSCWV. The Merger Agreement also contains certain termination rights for both FirstEnergy and Allegheny Energy, and further provides for the payment of fees and expenses upon termination under specified circumstances.

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FirstEnergy and Allegheny Energy currently anticipate completing the merger in the first 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.
In connection with the proposed merger, FirstEnergy recordedincurred approximately $7$14 million ($511 million after tax) of merger transaction costs in the secondthird quarter and approximately $21$35 million ($1526 million after tax) of merger transaction costs in the first sixnine months of 2010. These costs are expensedcharged to expense as incurred.
FERC
On May 11, 2010, FirstEnergy and Allegheny Energy filed an application with the FERC for approval of their proposed merger. Under the Federal Power Act, FERC has 180 days to rule on thea 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 the 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 May 14 and May 18,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 applicationsa comprehensive settlement with the PPUC and the PSCWV, respectively, for approval of their proposed merger. Pennsylvania and West Virginia laws impose no statutory timeframe for their commissions’ consideration of a merger application, but procedural schedules have been established, and final decisions are anticipated early in 2011. On May 27, 2010, FirstEnergy and Allegheny Energy filed an application for approvalthat addresses issues raised by 18 of the proposedparties 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 withclose, 675 jobs for the MDPSC.following 12 months, 650 jobs for the next year and 600 jobs for each of the next two years. The MDPSCsettlement 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 requiredsubject to issue an order no later than 180 days after an application is filed, but under good cause MDPSC may give itself a 45-day extension, which itapproval by the PPUC, and does not resolve issues raised by parties who did when it issued its initial ordernot join in the matter. An order from the MDPSC is therefore expected by January 7, 2011. On June 14, 2010, FirstEnergy and Allegheny Energy completed their application with the VSCC. The VSCC is required to rule on the merger application in 60 days, subject to up to a 120-day extension. In its order issued June 25, 2010, the VSCC extended the period for its review by 30 days; therefore the companies expect a decision by September 13, 2010.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, which extends the HSR Act waiting period for an additional 30 days from the date that the requested information is supplied to the DOJ.
Form S-4 Registration Statement
On July 16, 2010, FirstEnergy’s registration statement on Form S-4 containing a joint proxy statement/prospectus relating to the proposed merger (Registration Statement) was declared effective by the SEC. The joint proxy statement/prospectus contained in the Registration Statement was first mailed to FirstEnergy and Allegheny Energy shareholders on or about July 23, 2010. FirstEnergy and Allegheny Energy will each hold a special meeting of shareholders on September 14, 2010 in connectioncontinue to cooperate with the proposed merger.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 June 1,August 20, 2010, FGCO purchased $15FES completed the remarketing of $250 million fixed rateof PCRBs. Of the $250 million, $235 million of PCRBs originally issued on its behalf. Subjectwere converted from a variable interest rate to market conditions, FGCO plans to remarket thea 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 well asa result, reducing exposure to variable interest rates over the short-term. These remarketings included two series: $235 million of PCRBs purchased in April, in the near future.
Penn redeemed $1that now bear a per-annum rate of 2.25% and are subject to mandatory purchase on June 3, 2013; and $15 million of PCRBs due October 1, 2013that 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 $6.5remarketing 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 7.65% FMBs due in 2023notes payable to FirstEnergy, including $9 million of interest and $63 million of bank loans that were scheduled to mature on July 30,November 16, 2010.
During the second quarter of 2010, FirstEnergy executed 13 interest rate swap contracts totaling $3.2 billion. These contacts were subsequently terminated to take advantage of favorable market conditions, and resulted in cash proceeds of $126.7 million. These Additional proceeds will generally be amortized to earnings over the lifeused for general company purposes, including an $11 million repayment of the underlying debt.a third-party seller’s note maturing October 29, 2010.

 

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Operational Matters
Davis-Besse RefuelingPlant Operational Changes
On June 3,August 12, 2010, modificationsFGCO announced that it would be making operational changes to some of 24its 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 69 control rod drive mechanism (CRDM) nozzles onDavis-Besse operating license. By a letter dated October 18, 2010, the reactor head were completed atNRC determined that the Davis-Besse Nuclear Power Station. These nozzles were identified during Davis-Besse’s refueling outagelicense renewal application was complete and reactor head inspection that began February 28, 2010. The extended outage atacceptable for docketing and further review. Davis-Besse resulted in a $5 million impact on O&M thiscurrently 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, while approximately $40 millionFGCO re-evaluated the schedule for completing the Fremont Plant (707 MW) due to current market conditions and the extension of the costs relatedtax 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 modifications to the CRDM were capitalized. The plant was originally scheduled to have a new reactor head installed in 2014. This timeline was voluntarily accelerated, and FirstEnergy announced that a new reactor head will be installed in the fall of 2011. The new head was manufactured in France and is expected to arrive at the plant in the fall of 2010 to undergo a series of pre-service inspections. Davis-Besse returned to service on June 29, 2010.
Legacy Power Contracts
In July 2010, FES entered into financial transactions that offset the mark-to-market impact of legacy purchased power contracts totaling 500 MW entered into in 2008 for delivery in 2010 and 2011 and which were marked to market beginning in December 2009. These financial transactions eliminate the volatility associated with marking these contracts to market through the end of 2011.capital budget.
Regulatory Matters — General
DOE Smart Grid Grants and Smart Meter Implementation
On June 3, 2010, FirstEnergy and the DOE signedreceived DOE’s grants totaling $57.4 million, that were awarded as part of the American Recovery and Reinvestment Act, to be used to introduce smart grid technologies in targeted areas inof Pennsylvania, Ohio and New Jersey. The DOE grants represent 50% of the funding for the $114.9 million FirstEnergy investmentFE plans to invest in smart grid technologies; thetechnologies. The PPUC and the NJBPU have alreadypreviously approved recovery for the remainingapplicable utilities portion of smart grid costs. The PUCO issued an order on June 30, 2010, approving FirstEnergy’scosts, and FirstEnergy has begun implementing smart grid program, but FirstEnergy has delayed implementation of the Ohio portionprograms in Pennsylvania and New Jersey. Implementation of the program until therein Ohio is more certainty regardingunderway following clarification by the PUCO in its entry on rehearing issued August 25, 2010 that the Ohio Companies are entitled to cost recovery for the portion of theany costs not covered by the DOE grant.
Regulatory Matters — Ohio
Electric Security Plan FilingNew 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 filedwill 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 second Supplemental Stipulationfive 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 the PUCO on July 22, 2010, to supplement the ESP Stipulation filed on March 23, 2010,distribution, subtransmission and the Supplemental Stipulation filed on May 13, 2010. An additional four signatories weregeneral and intangible plant that was not included in the Supplemental Stipulations, joiningOhio 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 17 original signatory partiesthree-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 supportparticipated in the ESP. A finalauction, with four bidders winning tranches in the auction. The auction consisted of twelve rounds. On October 22, 2010, the PUCO orderaccepted the results of the auction. The next auction is pending.scheduled for January 2011.

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Regulatory Matters — Pennsylvania
Met-Ed and Penelec TSCDefault Service Plan
On MayOctober 20, 2010, the PPUC approved the revised TSC for Met-Ed and Penelec. The revised TSC rates were slightly increased for Met-Ed and slightly decreased for Penelec, and are effective forresults of the period of June 1, 2010 to December 31, 2010. The PPUC’s Order of March 3, 2010, which denies the recovery of marginal transmission losses through the TSC for the period of June 1, 2007 through March 31, 2008, remains subject to an appeal that is currently pending in the Commonwealth Court of Pennsylvania.
Met-Ed and Penelec Default Service Plan
On May 27, 2010, the thirdfinal of four auctions held to procure the default service requirements for Met-Ed and Penelec customers who choose not to shop with an alternative supplier. For the five-month period of January 1, 2011 to May 31, 2011, the tranche-weighted average prices ($/MWh) for Met-Ed’s residential and commercial classes were $72.81$67.10 and $72.29,$68.28, respectively; Penelec’s tranche-weighted average prices were $62.04$55.76 and $63.35$58.24 for its residential and commercial classes, respectively. There will be another auction inThe October 2010 to procureauction is the remaining supply for this period. The May 2010 auction was also the firstsecond of four auctions to procure commercial default service requirements for the 12-month period of June 1, 2011 to May 31, 2012 and residential requirements for the 24-month period of June 1, 2011 to May 31, 2013. For Met-Ed and Penelec commercial customers the tranche-weighted average price ($/MWh) was $66.32$63.97 and $57.60,$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 threetwo auctions for these products will be conducted in October 2010, January 2011 and March 2011.

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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
RPM Base Residual AuctionMISO Multi-Value Project Rule Proposal
On May 14,September 10, 2010, PJM releasedFirstEnergy filed a protest to MISO’s MVP proposal. FirstEnergy believes that MISO’s proposal to allocate costs of MVP projects across the resultsentire 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 the 2013/2014 RPM Base Residual Auction. The auction cleared 152,743 MW of unforced capacityprogress to date in the RTO Zone, which includesATSI move to PJM, it would be unjust and unreasonable to allocate any MVP costs to the ATSI zone, ator to ATSI. FirstEnergy is unable to predict the Resource Clearing Priceoutcome of $27.73/MW-day. The Clearing Price in MAAC, which includes Met-Ed and Penelec zones and EMAAC which includes the Jersey Central zone, were $226.15/MW-day and $245.00/MW-day, respectively.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 Servicestransmits and distributes electricity through our eight utility operating companies, serving 4.5 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey and purchases power for its POLR and default service requirements in Ohio, Pennsylvania and New Jersey. Its revenues are primarily derived from the delivery of electricity within our service areas, cost recovery of regulatory assets and the sale of electric generation service to retail customers who have not selected an alternative supplier (default service) in its Ohio, Pennsylvania and New Jersey franchise areas. Its results reflect the commodity costs of securing electric generation from FES and from non-affiliated power suppliers, the net PJM and MISO transmission expenses related to the delivery of the respective generation loads and the deferral and amortization of certain fuel costs.
Competitive Energy Servicessupplies electric power to end-use customers through retail and wholesale arrangements, including associated company power sales to meet all or a portion of the POLR and default service requirements of our Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Maryland, Michigan and Michigan.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.

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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 1112 to the consolidated financial statements. Earnings available to FirstEnergy by major business segment were as follows:
                                                
 Three Months Ended Six Months Ended  Three Months Ended Nine Months Ended 
 June 30 June 30  September 30 September 30 
 Increase Increase  Increase Increase 
 2010 2009 (Decrease) 2010 2009 (Decrease)  2010 2009 (Decrease) 2010 2009 (Decrease) 
 (In millions, except per share data)  (In millions, except per share data) 
Earnings By Business Segment:
 
Earnings (Loss) By Business Segment:
 
Energy delivery services $143 $154 $(11) $257 $136 $121  $224 $148 $76 $481 $285 $196 
Competitive energy services 125 276  (151) 201 431  (230)  (27) 183  (210) 174 614  (440)
Other and reconciling adjustments*  (3)  (16) 13  (38)  (34)  (4)  (18)  (97) 79  (56)  (131) 75 
                          
Total $265 $414 $(149) $420 $533 $(113) $179 $234 $(55) $599 $768 $(169)
                          
  
Basic Earnings Per Share
 $0.87 $1.36 $(0.49) $1.38 $1.75 $(0.37) $0.59 $0.77 $(0.18) $1.97 $2.52 $(0.55)
Diluted Earnings Per Share
 $0.87 $1.36 $(0.49) $1.37 $1.75 $(0.38) $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.

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Summary of Results of Operations — SecondThird Quarter 2010 Compared with SecondThird Quarter 2009
Financial results for FirstEnergy’s major business segments in the secondthird quarter of 2010 and 2009 were as follows:
                                
 Energy Competitive Other and    Energy Competitive Other and   
 Delivery Energy Reconciling FirstEnergy  Delivery Energy Reconciling FirstEnergy 
Second Quarter 2010 Financial Results Services Services Adjustments Consolidated 
Third Quarter 2010 Financial Results Services Services Adjustments Consolidated 
 (In millions)  (In millions) 
Revenues:  
External  
Electric $2,243 $728 $— $2,971  $2,609 $905 $— $3,514 
Other 130 50  (23) 157  148 52  (21) 179 
Internal 19 539  (558) —  60 599  (659) — 
                  
Total Revenues 2,392 1,317  (581) 3,128  2,817 1,556  (680) 3,693 
                  
  
Expenses:  
Fuel — 351  (1) 350  — 401  (1) 400 
Purchased power 1,291 319  (558) 1,052  1,473 470  (659) 1,284 
Other operating expenses 352 337  (16) 673  422 347  (31) 738 
Provision for depreciation 115 66 9 190  111 62 9 182 
Amortization of regulatory assets 161 — — 161  176 — — 176 
Deferral of new regulatory assets — — — —  — — — — 
Impairment of long lived assets — 292 — 292 
General taxes 145 25 6 176  174 26 6 206 
                  
Total Expenses 2,064 1,098  (560) 2,602  2,356 1,598  (676) 3,278 
                  
  
Operating Income 328 219  (21) 526  461  (42)  (4) 415 
                  
Other Income (Expense):  
Investment income 27 13  (9) 31  23 28  (5) 46 
Interest expense  (124)  (55)  (28)  (207)  (125)  (53)  (30)  (208)
Capitalized interest 1 24 15 40  2 23 16 41 
                  
Total Other Expense  (96)  (18)  (22)  (136)  (100)  (2)  (19)  (121)
                  
  
Income Before Income Taxes 232 201  (43) 390  361  (44)  (23) 294 
Income taxes 89 76  (31) 134  137  (17)  (1) 119 
                  
Net Income (Loss) 143 125  (12) 256  224  (27)  (22) 175 
Noncontrolling interest loss — —  (9)  (9)
Loss attributable to noncontrolling interest — —  (4)  (4)
                  
Earnings available to FirstEnergy Corp. $143 $125 $(3) $265  $224 $(27) $(18) $179 
                  

 

6967

                                
 Energy Competitive Other and    Energy Competitive Other and   
 Delivery Energy Reconciling FirstEnergy  Delivery Energy Reconciling FirstEnergy 
Second Quarter 2009 Financial Results Services Services Adjustments Consolidated 
 (In millions) 
Third Quarter 2009 Financial Results Services Services Adjustments Consolidated 
  (In millions) 
Revenues:  
External  
Electric $2,657 $205 $— $2,862  $2,804 $444 $— $3,248 
Other 135 299  (25) 409  138 46  (24) 160 
Internal — 839  (839) —  — 617  (617) — 
                  
Total Revenues 2,792 1,343  (864) 3,271  2,942 1,107  (641) 3,408 
                  
  
Expenses:  
Fuel — 276 — 276  — 302 — 302 
Purchased power 1,677 186  (839) 1,024  1,725 205  (617) 1,313 
Other operating expenses 328 315  (31) 612  366 331  (32) 665 
Provision for depreciation 110 68 7 185  112 69 7 188 
Amortization of regulatory assets 233 — — 233  261 — — 261 
Deferral of new regulatory assets  (45) — —  (45) — — — — 
Impairment of long lived assets — — — — 
General taxes 154 25 5 184  162 27 3 192 
                  
Total Expenses 2,457 870  (858) 2,469  2,626 934  (639) 2,921 
                  
  
Operating Income 335 473  (6) 802  316 173  (2) 487 
                  
Other Income (Expense):  
Investment income 35 6  (14) 27  46 159  (14) 191 
Interest expense  (114)  (32)  (60)  (206)  (116)  (46)  (193)  (355)
Capitalized interest 1 14 18 33  1 18 16 35 
                  
Total Other Expense  (78)  (12)  (56)  (146)  (69) 131  (191)  (129)
                  
  
Income Before Income Taxes 257 461  (62) 656  247 304  (193) 358 
Income taxes 103 185  (40) 248  99 121  (92) 128 
                  
Net Income (Loss) 154 276  (22) 408  148 183  (101) 230 
Noncontrolling interest loss — —  (6)  (6)
Loss attributable to noncontrolling interest — —  (4)  (4)
                  
Earnings available to FirstEnergy Corp. $154 $276 $(16) $414  $148 $183 $(97) $234 
                  
                                
Changes Between Second Quarter 2010 and         
Second Quarter 2009 Financial Results         
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 $(414) $523 $— $109  $(195) $461 $— $266 
Other  (5)  (249) 2  (252) 10 6 3 19 
Internal 19  (300) 281 —  60  (18)  (42) — 
                  
Total Revenues  (400)  (26) 283  (143)  (125) 449  (39) 285 
                  
  
Expenses:  
Fuel — 75  (1) 74  — 99  (1) 98 
Purchased power  (386) 133 281 28   (252) 265  (42)  (29)
Other operating expenses 24 22 15 61  56 16 1 73 
Provision for depreciation 5  (2) 2 5   (1)  (7) 2  (6)
Amortization of regulatory assets  (72) — —  (72)  (85) — —  (85)
Deferral of new regulatory assets 45 — — 45  — — — — 
Impairment of long lived assets — 292 — 292 
General taxes  (9) — 1  (8) 12  (1) 3 14 
                  
Total Expenses  (393) 228 298 133   (270) 664  (37) 357 
                  
  
Operating Income  (7)  (254)  (15)  (276) 145  (215)  (2)  (72)
                  
Other Income (Expense):  
Investment income  (8) 7 5 4   (23)  (131) 9  (145)
Interest expense  (10)  (23) 32  (1)  (9)  (7) 163 147 
Capitalized interest — 10  (3) 7  1 5 — 6 
                  
Total Other Expense  (18)  (6) 34 10   (31)  (133) 172 8 
                  
  
Income Before Income Taxes  (25)  (260) 19  (266) 114  (348) 170  (64)
Income taxes  (14)  (109) 9  (114) 38  (138) 91  (9)
                  
Net Income (Loss)  (11)  (151) 10  (152) 76  (210) 79  (55)
Noncontrolling interest loss — —  (3)  (3)
Loss attributable to noncontrolling interest — — — — 
                  
Earnings available to FirstEnergy Corp. $(11) $(151) $13 $(149) $76 $(210) $79 $(55)
                  

 

7068

Energy Delivery Services — SecondThird Quarter 2010 Compared with SecondThird 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
Residential19%
Commercial5%
Industrial11%
Total Distribution KWH Deliveries12%
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 $11$210 million in the secondthird quarter of 2010, compared to the secondthird 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 generation-relateddemand 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 absencePennsylvania 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 deferrals2009.
Wholesale revenues decreased $56 million due to reduced volumes and lower wholesale prices. The lower sales volumes were a result of new regulatory assets,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 amortizationunit 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 assets andasset impairment in 2009, partially offset by decreases in other operating expenses. Lower generation revenues were offset by lower purchased power costs.expenses.
Revenues —-
The decrease in total revenues resulted from the following sources:
                        
 Three Months    Nine Months   
 Ended June 30 Increase  Ended September 30 Increase 
Revenues by Type of Service 2010 2009 (Decrease)  2010 2009 (Decrease) 
 (In millions) 
  (In millions) 
Distribution services $851 $813 $38  $2,774 $2,578 $196 
              
Generation sales:  
Retail 1,097 1,514  (417) 3,540 4,679  (1,139)
Wholesale 180 162 18  628 544 84 
              
Total generation sales 1,277 1,676  (399) 4,168 5,223  (1,055)
              
Transmission 200 259  (59) 638 808  (170)
Other 64 44 20  172 146 26 
              
Total Revenues $2,392 $2,792 $(400) $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  53%
Industrial  1310%
    
Total Distribution KWH Deliveries  87%
    
Higher deliveries to residential and commercial customers reflected increased weather-related usage in the second quarterfirst nine months of 2010, as cooling2010. Cooling degree days increased by 94%69%, partially offset by an 11% decrease in heating degree days from the same period in 2009. The increase in distribution deliveries to industrial customers was primarily due to recovering economic conditions in FirstEnergy’s service territory compared to the second quarter of 2009. In the industrial sector, KWH deliveries increased to major automotive customers (39%(22%), refinery customers (11%) and steel customers (60%(44%). Distribution due to recovering economic conditions. The increase in distribution service revenues increased primarily due toalso reflects the recovery of the PAPennsylvania 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 $399 million$1.1 billion decrease in generation revenues in the second quarterfirst nine months of 2010 compared to the second quartersame period of 2009:
        
 Increase  Increase 
Source of Change in Generation Revenues (Decrease)  (Decrease) 
 (In millions)  (In millions) 
 
Retail:  
Effect of 29.4% decrease in sales volumes $(444)
Effect of 26.8% decrease in sales volumes $(1,254)
Change in prices 27  115 
      
  (417)  (1,139)
      
 
Wholesale:  
Effect of 10.1% decrease in sales volumes  (16)
Effect of 7.1% decrease in sales volumes  (38)
Change in prices 34  122 
      
 18  84 
      
Decrease in Generation Revenues $(399)
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 second quarterfirst nine months of 2010, which2010. That condition is expected to continue to impact retail generationthe comparative sales partially offset by higher generation revenues related tolevels for the recoveryremainder of transmission costs now provided for in the generation rate established under the CBP.2010. Total generation KWH provided by alternative suppliers as a percentage of total KWH deliveries for the Ohio Companies increased to 61%60% in the second quarterfirst nine months of 2010 as there was no shoppingfrom 7% in the second quartersame 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.

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The increase in wholesale generation revenues reflected higher prices for Met-Ed’s and Penelec’sincreased capacity sales of NUG power toby Met-Ed and Penelec in the PJM market.

75

Transmission revenues decreased $59$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 $393 million due to the following:
•Purchased power costs were $386 million lower in the second quarter of 2010 due to lower volume requirements, partially offset by an increase in unit costs from non-affiliates. 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. The decrease in volumes from FES principally resulted from the increase in customer shopping in the Ohio Companies’ service territories, as described above.
•The increase in unit costs from non-affiliates in the second quarter of 2010 resulted from higher capacity prices in the PJM market for Met-Ed and Penelec compared to the second quarter of 2009. The decrease in unit costs from FES was principally due to the lower weighted average unit price per KWH for the Ohio Companies established under the CBP auction effective June 1, 2009.
     
  Increase 
Source of Change in Purchased Power (Decrease) 
  (In millions) 
     
Purchases from non-affiliates:    
Change due to increased unit costs $156 
Change due to decreased volumes  (280)
    
   (124)
    
     
Purchases from FES:    
Change due to decreased unit costs  (67)
Change due to decreased volumes  (191)
    
   (258)
    
     
Increase in NUG costs deferred  (4)
    
Net Decrease in Purchased Power Costs $(386)
    
•Administrative and general costs, including labor and employee benefit expenses, increased $9 million primarily due to a higher level of incentive compensation earned this year, partially offset by lower payroll expenses due to staffing reductions implemented in 2009.
•Energy Efficiency program costs increased $14 million in the second quarter of 2010 compared to the second quarter of 2009.
•Forestry contractor costs decreased by $3 million in the second quarter of 2010 compared to the second quarter of 2009, as more resources were dedicated to capital projects in 2010.
•A favorable JCP&L labor settlement reduced expenses by $7 million in the second quarter of 2010.
•Transmission costs, net of regulatory asset amortization expense, decreased by $61 million primarily due to the transfer of transmission cost responsibility to generation providers under the CBP.
•The deferral of new regulatory assets decreased $45 million in the second quarter of 2010 principally due to reduced CEI purchased power cost deferrals in the second quarter of 2009.
•Depreciation expense increased $5 million due to property additions since the second quarter of 2009.
•General taxes decreased $9 million primarily due to a favorable Ohio property tax settlement in 2010.

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Other Expense —
Other expense increased $18 million in the second quarter of 2010 compared to the second quarter of 2009 primarily due to higher interest expense associated with debt issuances by the Utilities since the second quarter of 2009.
Competitive Energy Services — Second Quarter 2010 Compared with Second Quarter 2009
Net income decreased by $151 million in the second quarter of 2010, compared to the second quarter of 2009, primarily due to the absence of a $252 million gain ($158 million after tax) in 2009 from the sale of a 9% participation interest in OVEC.
Revenues —
Total revenues, excluding the OVEC sale, increased $226 million in the second quarter of 2010 primarily due to an increase in direct and government aggregation sales volumes, partially offset by decreases in POLR sales to the Ohio Companies and wholesale sales.
The decrease in total revenues resulted from the following sources:
             
  Three Months    
  Ended June 30  Increase 
Revenues by Type of Service 2010  2009  (Decrease) 
  (In millions) 
             
Direct and Government Aggregation $586  $83  $503 
POLR  586   839   (253)
Wholesale  95   122   (27)
Transmission  19   16   3 
Sale of OVEC participation interest  —   252   (252)
Other  31   31   — 
          
Total Revenues $1,317  $1,343  $(26)
          
The increase in direct and government aggregation revenues of $503 million resulted from increased revenue in both the MISO and PJM markets. The increase in revenue primarily resulted from the acquisition of new commercial and industrial customers as well as new government aggregation contracts with communities in Ohio that provide generation to 1.1 million residential and small commercial customers at the end of June 2010 compared to 21,000 at the end of June 2009.
The decrease in POLR revenues of $253 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 the second quarter 2010 reflected the results of the May 2009 power procurement process. The increased revenues to the Pennsylvania Companies resulted from FES supplying Met-Ed and Penelec with volumes previously supplied through a third-party contract and at prices that were slightly higher than in the second quarter of 2009.
Wholesale revenues decreased $27 million due to reduced volumes, reflecting increased retail sales in Ohio and lower prices.
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 $345 
Change in prices  (16)
    
   329 
    
     
Government Aggregation:    
Effect of increase in sales volumes  174 
Change in prices  — 
    
   174 
    
Net Increase in Direct and Gov’t Aggregation Revenues $503 
    

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Source of Change in Wholesale Revenues Decrease 
  (In millions) 
     
POLR:    
Effect of 20.4% decrease in sales volumes $(171)
Change in prices  (82)
    
   (253)
    
     
Wholesale:    
Effect of 21.9% decrease in sales volumes  (15)
Change in prices  (12)
    
   (27)
    
     
Decrease in Wholesale Revenues $(280)
    
Transmission revenues increased $3 million due primarily to higher MISO congestion revenue.
Expenses —
Total expenses increased $228 million in the second quarter of 2010 due to the following:
•Fuel costs increased $75 million due to increased generation volumes primarily at the fossil units ($73 million) and higher unit prices ($2 million). The increase in unit prices was due primarily to higher nuclear fuel unit prices following the refueling outages that occurred in 2009.
•Purchased power costs increased $133 million due primarily to higher volumes purchased ($162 million) and higher unit costs ($6 million), partially offset by power contract mark-to-market adjustments ($35 million). In July 2010, FES entered into financial transactions that offset the mark-to-market impact of legacy purchased power contracts totaling 500 MW entered into in 2008 for delivery in 2010 and 2011 and which were marked-to-market beginning in December 2009. These financial transactions eliminate the volatility associated with marking these contracts to market through the end of 2011.
•Fossil operating costs decreased $3 million due primarily to lower professional and contractor costs, partially offset by reduced gains on the sale of emission allowances.
•Nuclear operating costs decreased $17 million due primarily to lower labor and professional and contractor costs due to one less refueling outage in 2010 as compared to the same period of 2009.
•Transmission expenses increased $26 million due primarily to increases in MISO of $63 million from higher network and ancillary costs, partially offset by lower PJM transmission expenses of $37 million due to lower congestion and loss costs.
•Other expenses increased $14 million primarily due to increases in uncollectible customer accounts and agent fees associated with the growth in direct and government aggregation sales.
Other Expense —
Total other expense in the second quarter of 2010 was $6 million higher than the second quarter of 2009, primarily due to a $13 million increase in interest expense from new long-term debt issued combined with the restructuring of existing long-term debt, partially offset by a $7 million increase in investment income resulting from more favorable performance of the nuclear decommissioning trust investments ($6 million).
Other — Second Quarter of 2010 Compared with Second 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 $13 million increase in earnings available to FirstEnergy in the first quarter of 2010 compared to the same period in 2009. The increase resulted primarily from reduced interest expense on holding company debt resulting from the September 2009 tender offer ($20M), partially offset by increased operating expenses.

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

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

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

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The increase in distribution deliveries by customer class is summarized in the following table:
Electric Distribution KWH Deliveries
Residential1%
Commercial2%
Industrial10%
Total Distribution KWH Deliveries4%
Higher deliveries to residential and commercial customers reflected increased weather-related usage in the first six months of 2010. Cooling degree days increased by 94%, partially offset by a 10% decrease in heating degree days from the same period in 2009. The increase in distribution deliveries to industrial customers was primarily due to recovering economic conditions in FirstEnergy’s service territory compared to the first six months of 2009. In the industrial sector, KWH deliveries increased to major automotive customers (26%) and steel customers (44%). Distribution service revenues increased primarily due to the recovery of the PA Energy Efficiency and Conservation charges as approved by the PPUC in March 2010 and the accelerated recovery of deferred distribution costs in Ohio, partially offset by a reduction in the transition rate for CEI effective June 1, 2009.
The following table summarizes the price and volume factors contributing to the $806 million decrease in generation revenues in the first six months of 2010 compared to the same period of 2009:
     
  Increase 
Source of Change in Generation Revenues (Decrease) 
  (In millions) 
Retail:    
Effect of 30% decrease in sales volumes $(939)
Change in prices  85 
    
   (854)
    
     
Wholesale:    
Effect of 12.2% decrease in sales volumes  (42)
Change in prices  90 
    
   48 
    
Net Decrease in Generation Revenues $(806)
    
The decrease in retail generation sales volumes was primarily due to an increase in customer shopping in the Ohio Companies’ service territories in the first six months of 2010, which is expected to continue to impact retail generation sales, partially offset by higher generation revenues related to the recovery of transmission costs now provided for in the generation rate established under the CBP. Total generation KWH provided by alternative suppliers as a percentage of total KWH deliveries for the Ohio Companies increased to 57% in the first six months of 2010, as there was no shopping in the same period of 2009.
The increase in wholesale generation revenues reflected higher prices for Met-Ed’s and Penelec’s NUG sales to the PJM market.
Transmission revenues decreased $162 million primarily due to the termination of the Ohio Companies’ transmission tariff effective June 1, 2009; recovery of transmission costs is now through the generation rate established under the CBP.
Expenses —
Total expenses decreased by $1,103 million$1.4 billion due to the following:
Purchased power costs were $867 million$1.1 billion lower in the first sixnine months of 2010 in large part due to lower volume requirements partially offset by an increase in unit costs for purchased power from non-affiliates.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 the above described increase in customer shopping in the Ohio Companies’ service territories. The decrease in volumes from FES principally resulted from thean increase in customer shopping in the Ohio Companies’ service territories as 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 sixnine months of 2010 resulted from higher capacity prices in the PJM market for Met-Ed and Penelec compared to the first sixnine 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.

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 Increase  Increase 
Source of Change in Purchased Power (Decrease)  (Decrease) 
 (In millions)  (In millions) 
Purchases from non-affiliates:  
Change due to increased unit costs $346  $506 
Change due to decreased volumes  (703)  (1,140)
      
  (357)  (634)
      
 
Purchases from FES:  
Change due to decreased unit costs  (160)  (230)
Change due to decreased volumes  (343)  (289)
      
  (503)  (519)
      
  
Increase in NUG costs deferred  (7)
Decrease in costs deferred 34 
      
Net Decrease in Purchased Power Costs $(867) $(1,119)
      
MISO/PJM transmissionLabor and employee benefit expenses decreased $43by $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 the recovery ofhigher PJM network transmission expenses and congestion costs, now provided forpartially offset by lower MISO network transmission expenses that are not reflected in the generation rate established under the CBP, partially offset by higher PJM congestion charges.
Administrative and general costs, including labor and employee benefits expenses, decreased by $22 million in the first six month of 2010 compared toMay 2009 due to lower payroll expenses resulting from staffing reductions implemented in 2009.
Other operating expenses decreased $28 million due to higher economic development commitments recognized in the first quarter of 2009 relating to the amended ESP and a favorable labor settlement of $7 million for JCP&L recognized in the second quarter of 2010.Ohio CBP.
Amortization of regulatory assets decreased $269$354 million due primarily to the absence of the $216 million impairment of CEI’s regulatory assets in the second quarter of 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 filing of the Ohio Companies’ ESP on March 23, 2010.ESP.
The deferral of new regulatory assets decreased $136 million in the first sixnine months of 2010 principally due to reduced CEIthe absence of purchased power cost deferrals for CEI in the second quarter of 2009.
Depreciation expense increased $9$8 million due to property additions since the secondthird quarter of 2009.
General taxes decreased $17$5 million due primarily to favorable Ohio and Pennsylvania tax settlements in 2010.2010 partially offset by higher gross receipts taxes.

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Other Expense —-
Other expense increased $37$67 million in the first sixnine months of 2010 compared to the first sixnine 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 secondthird quarter of 2009.2009 ($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 SixNine Months of 2010 Compared to First SixNine Months of 2009
Net income decreased by $230$440 million in the first sixnine months of 2010, compared to the first sixnine 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.margins also contributed to the decline in net income.

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Revenues —-
Total revenues, excludingExcluding the impact of the 2009 gain on the OVEC sale, total revenues increased $388$839 million in the first sixnine months of 2010 compared to the same period in 2009 primarily due to an increase in direct and government aggregation sales volumes and sales of RECs, partially offset by decreases in POLR sales to the Ohio Companies and wholesale sales.

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The increase in reported segment revenues resulted from the following sources:
                        
 Six Months    Nine Months   
 Ended June 30 Increase  Ended September 30 Increase 
Revenues by Type of Service 2010 2009 (Decrease)  2010 2009 (Decrease) 
 (In millions)  (In millions) 
Direct and Government Aggregation $1,097 $174 $923  $1,814 $406 $1,408 
POLR 1,260 1,732  (472) 1,911 2,369  (458)
Wholesale 186 311  (125) 322 503  (181)
Transmission 36 41  (5) 58 57 1 
RECs 67 — 67  67 — 67 
Sale of OVEC participation interest — 252  (252) — 252  (252)
Other 61 61 —  93 91 2 
              
Total Revenues $2,707 $2,571 $136  $4,265 $3,678 $587 
              
The increase in direct and government aggregation revenues of $923$1,408 million resulted from increased revenue in both the MISO and PJM markets. The increase in revenue primarily resulted from the acquisition of new commercial and industrial customers, as well as new government aggregation contracts with communities in Ohio that provide generation to 1.11.2 million residential and small commercial customers at the end of JuneSeptember 2010 compared to 21,000500,000 such customers at the end of JuneSeptember 2009, partially offset by lower unit prices. During January 2010, FES began supplying powerIn addition, sales to approximately 425,000 NOPEC customers.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 $472$458 million was due to lower sales volumes and lower unit prices 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.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 $125$181 million due to reduced volumes reflecting market declines and lower prices.
The following tables summarize the price and volume factors contributing to changes in revenues from generation sales:
     
  Increase 
Source of Change in Direct and Government Aggregation (Decrease) 
  (In millions) 
Direct Sales:    
Effect of increase in sales volumes $633 
Change in prices  (47)
    
   586 
    
     
Government Aggregation:    
Effect of increase in sales volumes  337 
Change in prices  — 
    
   337 
    
Net Increase in Direct and Gov’t Aggregation Revenues $923 
    
     
Source of Change in Wholesale Revenues Decrease 
  (In millions) 
POLR:    
Effect of 15.1% decrease in sales volumes $(262)
Change in prices  (210)
    
   (472)
    
     
Wholesale:    
Effect of 56.7% decrease in sales volumes  (123)
Change in prices  (2)
    
   (125)
    
Decrease in Wholesale Revenues $(597)
    
Transmission revenues decreased $5 million due primarily to lower PJM congestion revenue.

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Expenses —
Total expenses increased $540 million in the first six months of 2010sales volumes were due to the following factors:
Fuel costsavailable capacity serving increased $100 million due to increased generation volumes ($44 million) and higher unit prices ($56 million). The increaseretail sales in unit prices was due primarily to higher nuclear fuel unit prices following the refueling outages that occurred in 2009 and increased coal transportation costs.
Purchased power costs increased $423 million due primarily to higher volumes purchased ($484 million), and power contract mark-to-market adjustments ($17 million), partially offset by lower unit costs ($78 million).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 were marked-to-market beginning inthat have been marked to market since December 2009. These financial transactions eliminatemitigate the volatility associated with markingof these contracts to market through the end of 2011.2011 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 $2$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 $37$39 million due primarily to lower labor, and professionalconsulting and contractor costs. The sixnine months ended JuneSeptember 2010 had one less refueling outage and fewer extended outages than the same period of 2009.
Transmission expenses increased $33$36 million due primarily to increased costs in MISO of $106$152 million from higher network, ancillary and ancillarycongestion costs, partially offset by lower PJM transmission expenses of $73$116 million due to lower congestion and loss costs.
•Other expenses increased $20 million primarily due to increases in uncollectible customer accounts and agent fees associated with the growth in direct and government aggregation sales.
•General taxes increased $3 million due to sales taxes on higher revenues.
Other 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 sixnine months ending JuneSeptember 2010 was $9$124 million lowerhigher than the same period in 2009, primarily due to a $37decrease in nuclear decommissioning trust investment income ($94 million) and a $30 million increase in investment income resultingnet interest expense from more favorable performance of the nuclear decommissioning trust investments, partially offset by a $28 million increase in interest expense. Interest expense increased because of new issuances of long-term debt issued combined with the restructuring of existing long-term debt.PCRBs.
Other — First SixNine Months of 2010 Compared to First SixNine Months of 2009
Financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a $4$75 million decreaseincrease in earnings available to FirstEnergy in the first sixnine months of 2010 compared to the same period in 2009. The decreaseincrease resulted primarily from increased other operating expenses and depreciationthe absence of debt retirement costs that were incurred in the third quarter of 2009 in connection with the tender offer for holding company debt ($28139 million), decreased interest expense associated with the debt retirement ($56 million) and increased interest income tax expense ($4116 million), partially offset by reduced interestincreased depreciation and other operating expenses ($30 million) and income tax expense on holding company debt ($52132 million) which was primarily the result of a September 2009 tender offer..
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 those periods.any annual period may in aggregate vary from the indicated amount due to circumstances considered by FirstEnergy’s Board of Directors at the time of the actual declarations) and a successful merger integration.

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As of JuneSeptember 30, 2010, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was principally due to short-term borrowings ($1.51.0 billion) and the classification of certain variable interest rate PCRBs as currently payable long-term debt. Currently payable long-term debt as of JuneSeptember 30, 2010, included the following (in millions):
        
Currently Payable Long-term Debt  
PCRBs supported by bank LOCs (1)
 $1,318  $1,318 
FGCO and NGC unsecured PCRBs (1)
 75  90 
Penelec FMBs (2)
 24  24 
NGC collateralized lease obligation bonds
 50  50 
Sinking fund requirements
 41  34 
Other notes (2)(3)
 63  74 
      
 $1,571  $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 $1.5$1.0 billion of short-term borrowings as of JuneSeptember 30, 2010 and $1.2 billion as of December 31, 2009. FirstEnergy’s available liquidity as of July 31,October 22, 2010, is summarized in the following table:
                             
 Available  Available 
Company Type Maturity Commitment Liquidity  Type Maturity Commitment Liquidity 
 (In millions)      (In millions) 
FirstEnergy(1)
 Revolving Aug. 2012 $2,750 $1,407  Revolving Aug. 2012 $2,750 $1,650 
FirstEnergy Solutions Bank line Mar. 2011 100 —  Term loan Mar. 2011 100 — 
Ohio and Pennsylvania Companies Receivables financing Various(2) 395 267  Receivables financing Various(2) 395 245 
          
 Subtotal $3,245 $1,674  Subtotal $3,245 $1,895 
 Cash — 127  Cash — 911 
          
 Total $3,245 $1,801  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.

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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 JuneSeptember 30, 2010:
                
 Revolving Regulatory and  Revolving Regulatory and 
 Credit Facility Other Short-Term  Credit Facility Other Short-Term 
Borrower Sub-Limit Debt Limitations  Sub-Limit Debt Limitations 
 (In millions)  (In millions) 
FirstEnergy $2,750 $—(1) $2,750 $—(1)
FES 1,000  —(1) 1,000  —(1)
OE 500 500  500 500 
Penn 50  34(2) 50  34(2)
CEI  250(3) 500   250(3) 500 
TE  250(3) 500   250(3) 500 
JCP&L 425  405(2) 425  410(2)
Met-Ed 250  300(2) 250  300(2)
Penelec 250  300(2) 250  300(2)
ATSI  50(4) 50   50(4) 50 
   
(1) No regulatory approvals, statutory or charter limitations applicable.
 
(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 JuneSeptember 30, 2010, FirstEnergy’s and its subsidiaries’ debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:
     
Borrower    
FirstEnergy(1)
  61.160.2%
FES
  52.153.2%
OE
  53.453.1%
Penn
  31.330.8%
CEI
  59.357.6%
TE
  59.157.7%
JCP&L
  36.534.4%
Met-Ed
  38.237.6%
Penelec
  53.451.8%
ATSI
  50.348.8%
(1)As of June 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.

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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 sixnine months of 2010 was 0.51%0.53% per annum for the regulated companies’ money pool and 0.59%0.60% per annum for the unregulated companies’ money pool.

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Pollution Control Revenue Bonds
As of JuneSeptember 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 JuneSeptember 30, 2010:
               
 Aggregate LOC Reimbursements of Aggregate LOC Reimbursements of
LOC Bank Amount(2) LOC Termination Date LOC Draws Due Amount(2) LOC Termination Date LOC Draws Due
 (In millions)  (In millions) 
CitiBank N.A. $166 June 2014 June 2014 $166 June 2014 June 2014
The Bank of Nova Scotia 284 Beginning April 2011 Multiple dates(3) 284 Beginning April 2011 Multiple dates(3)
The Royal Bank of Scotland 131 June 2012 6 months 131 June 2012 6 months
Wachovia Bank 153 March 2014 March 2014 152 March 2014 March 2014
Barclays Bank(1)
 528 Beginning December 2010 30 days 528 Beginning December 2010 30 days
PNC Bank 70 Beginning November 2010 180 days 70 Beginning November 2010 180 days
            
Total $1,332     $1,331    
            
   
(1) Supported by 18 participating banks, with no one bank having more than 14% of the total commitment.
 
(2) Includes approximately $14$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).
In JuneOn August 20, 2010, FGCO purchasedFES 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 PCRBs originally issued on its behalf. In April 2010, FGCO purchased approximatelyand, as a result, reducing exposure to variable interest rates over the short-term. These remarketings included two series: $235 million variableof PCRBs that now bear a per-annum rate PCRBsof 2.25% and cancelled $237 million LOC held with KeyBank. Subjectare subject to market conditions, FGCO plans to remarket themandatory 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 well asof October 1, 2010. The LOCs for the $235remarketed series of PCRBs totaling $108 million PCRBs purchased in April, in the near future as market conditions permit.will terminate on November 1, 2010.
Long-Term Debt Capacity
As of JuneSeptember 30, 2010, the Ohio Companies and Penn had the aggregate capability to issue approximately $2.3$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 $107$116 million and $21$25 million, respectively, as of JuneSeptember 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 $377$380 million and $343$358 million, respectively, under provisions of their senior note indentures as of JuneSeptember 30, 2010.
Based upon FGCO’s FMB indenture, net earnings and available bondable property additions as of JuneSeptember 30, 2010, FGCO had the capability to issue $2.9$1.9 billion of additional FMBs under the terms of that indenture. In June 2009, a new FMB indenture became effective for NGC. Based upon NGC’s FMB indenture, net earnings and available bondable property additions, NGC had the capability to issue $294 million of additional FMBs as of JuneSeptember 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 subsidiariessubsidiaries’ 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 JuneSeptember 30, 2010.

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  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 JuneSeptember 30, 2010, FirstEnergy had $281$632 million inof cash and cash equivalents compared to $874 million as of December 31, 2009. As of JuneSeptember 30, 2010 and December 31, 2009, FirstEnergy had approximately $10$14 million and $12 million, respectively, of restricted cash included in other current assets on the Consolidated Balance Sheet.
During the first sixnine months of 2010, FirstEnergy received $655$730 million of cash dividends from its subsidiaries and paid $335$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 decreasedincreased by $244$609 million during the first sixnine months of 2010 compared to the comparable period in 2009, as summarized in the following table:
                        
 Six Months    Nine Months   
 Ended June 30 Increase  Ended September 30 Increase 
Operating Cash Flows 2010 2009 (Decrease)  2010 2009 (Decrease) 
 (In millions)  (In millions) 
Net income $405 $523 $(118) $580 $754 $(174)
Non-cash charges and other adjustments 789 719 70  1,648 1,755  (107)
Pension trust contribution —  (500) 500 
Working Capital and other  (336)  (140)  (196)  (155)  (545) 390 
              
 $858 $1,102 $(244) $2,073 $1,464 $609 
              

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The increasedecrease in non-cash charges and other adjustments is primarily due to higher deferred income taxes and investment tax credits ($90 million) and higher non-cash retirement benefit expenses ($66 million) recognized in the first six months of 2010, partially offset by lower net amortization of regulatory assets of ($133354 million), including the impact of CEI’s $216 million regulatory asset impairment recorded during the first quarter of 2009. 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 chargesis primarily resulted fromdue 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 $111 million decrease in cash collateral received, a $98prepaid assets of $345 million decrease in prepayments and other current assets, and a $43$250 million increase in accrued taxes, partially offset by a $188 million increase in receivables and a $23 million increase in materials and supplies. The change in prepayments and accrued taxes primarily relates to the timing of income tax payments.accounts receivable.

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Cash Flows From Financing Activities
In the first sixnine months of 2010, cash used for financing activities was $484$870 million compared to cash provided from financing activities of $426$617 million in the first sixnine months of 2009. The decrease was primarily due to activity during the first nine months of 2009 which included new debt issuances in 2009 and the repayment of short-term borrowings in 2010, partially offset by decreased long-term debt redemptionsretirements associated with a $1.2 billion senior note tender offer completed by FirstEnergy in 2010.September 2009. The following table summarizes security issuances (net of any discounts) and redemptions:
                
 Six Months  Nine Months 
 Ended June 30  Ended September 30 
Securities Issued or Redeemed 2010 2009  2010 2009 
 (In millions) 
  (In millions) 
New Issues
  
First mortgage bonds — 100  — 398 
Pollution control notes — 682  250 859 
Senior secured notes — 297  — 297 
Unsecured Notes — 600  1 2,597 
          
 $— $1,679  $251 $4,151 
          
  
Redemptions
  
First mortgage bonds 7 — 
Pollution control notes 251 682  251 687 
Senior secured notes 55 46  63 54 
Unsecured notes 100 153  101 1,472 
          
 $406 $881  $422 $2,213 
          
  
Short-term borrowings, net $281 $—  $(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 sixnine months of 2010 and 2009 by business segment:
                                
Summary of Cash Flows Property        Property       
Provided from (Used for) Investing Activities Additions Investments Other Total  Additions Investments Other Total 
 (In millions)  (In millions) 
Sources (Uses)
  
Six Months Ended June 30, 2010
 
Nine Months Ended September 30, 2010
 
Energy delivery services $(338) $87 $(20) $(271) $(546) $82 $11 $(453)
Competitive energy services  (605)  (11)  (1)  (617)  (860)  (26)  (53)  (939)
Other  (10)  (3) —  (13)  (18)  (3) 34 13 
Inter-Segment reconciling items  (44)  (22) —  (66)  (43)  (23) —  (66)
                  
Total $(997) $51 $(21) $(967) $(1,467) $30 $(8) $(1,445)
                  
  
Six Months Ended June 30, 2009
 
Nine Months Ended September 30, 2009
 
Energy delivery services $(343) $48 $(23) $(318) $(524) $(121) $(35) $(680)
Competitive energy services  (669) 2  (22)  (689)  (893)  (6)  (21)  (920)
Other  (119)  (7)  (3)  (129)  (133)  (11)  (144)
Inter-Segment reconciling items  (12)  (25) —  (37)  (25)  (25) 6  (44)
                  
Total $(1,143) $18 $(48) $(1,173) $(1,575) $(152) $(61) $(1,788)
                  

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Net cash used for investing activities in the first sixnine months of 2010 decreased by $206$343 million compared to the first sixnine months of 2009. The decrease was principally due to a $146$108 million decrease in property additions which reflects(principally lower AQC system expenditures,expenditures) and an increase in cash proceeds of approximately $116 million from the sale of assets of $98 million, partially offset by $105$110 million relating tospent by FES in the customer acquisition of customer intangible assets.process.
During the remaining two quartersquarter of 2010, capital requirements for property additions and capital leases are expected to be approximately $918$410 million, including approximately $155$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.

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As of JuneSeptember 30, 2010, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $3.9$3.8 billion, as summarized below:
        
 Maximum  Maximum 
Guarantees and Other Assurances Exposure  Exposure 
 (In millions)  (In millions) 
FirstEnergy Guarantees on Behalf of its Subsidiaries  
Energy and Energy-Related Contracts(1)
 $300  $300 
LOC (long-term debt) —Interest coverage(2)
 6  6 
FirstEnergy guarantee of OVEC obligations 300  300 
Other(3)
 294  226 
      
 900  832 
      
  
Subsidiaries’ Guarantees  
Energy and Energy-Related Contracts 54  54 
LOC (long-term debt) —Interest coverage(2)
 4  4 
FES’ guarantee of NGC’s nuclear property insurance 70  70 
FES’ guarantee of FGCO’s sale and leaseback obligations 2,413  2,413 
Other 2  2 
      
 2,543  2,543 
      
  
Surety Bonds 90  84 
LOC (long-term debt) — Interest coverage(2)
 3  3 
LOC (non-debt)(4)(5)
 372  380 
      
 465  467 
      
Total Guarantees and Other Assurances $3,908  $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 $80$15 million for nuclear decommissioning funding assurances, which has been reduced to $15 million in July 2010, and $161 million supporting OE’s sale and leaseback arrangement.arrangement, and $34 million for railcar leases.
 
(4) Includes $193$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.

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While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade to below investment grade, an acceleration or funding obligation or a “material adverse event,” the immediate posting of cash collateral, provision of a LOC or accelerated payments may be required of the subsidiary. As of JuneSeptember 30, 2010, FirstEnergy’s maximum exposure under these collateral provisions was $451$419 million, as shown below:
                        
Collateral Provisions FES Utilities Total  FES Utilities Total 
 (In millions)  (In millions) 
Credit rating downgrade to below investment grade(1) $314 $17 $331  $306 $68 $374 
Acceleration of payment or funding obligation 15 68 83 
Material adverse event 37 — 37 
Material adverse event (2)
 45 — 45 
              
Total $366 $85 $451  $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 $609$511 million consisting of $56$463 million due to “material adverse event” contractual clauses, $83a below investment grade credit rating, of which $175 million dueis related to an acceleration of payment or funding obligation, and $470$48 million due to a below investment grade credit rating.“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 $90$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 JuneSeptember 30, 2010, and forward prices as of that date, FES has posted collateral of $245$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 $107$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 $1.6$1.7 billion as of JuneSeptember 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.

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The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, FirstEnergy relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FirstEnergy uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making (see Note 35 to the consolidated financial statements). Sources of information for the valuation of commodity derivative contracts as of JuneSeptember 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  2010 2011 2012 2013 2014 Thereafter Total 
 (In millions)  (In millions) 
Prices actively quoted(1)
 $(5) $— $— $— $— $— $(5) $(2) $— $— $— $— $— $(2)
Other external sources(2)
  (322)  (332)  (147)  (34) 4  (17)  (848)  (328)  (369)  (164)  (53) 7  (10)  (917)
Prices based on models — — — —  (9) 138 129  — — — —  (9) 141 132 
                              
Total(3)
 $(327) $(332) $(147) $(34) $(5) $121 $(724) $(330) $(369) $(164) $(53) $(2) $131 $(787)
                              
   
(1) Represents exchange traded NYMEXNew York Mercantile Exchange futures and options.
 
(2) Primarily represents contracts based on broker and ICEIntercontinentalExchange quotes.
 
(3) Includes $547$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 JuneSeptember 30, 2010, an adverse 10% change in commodity prices would decrease net income by approximately $9$6 million ($64 million net of tax) during the next 12 months.
Interest Rate Swap Agreements — Fair Value Hedges
FirstEnergy useshas 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 arewere treated as fair value hedges of fixed-rate, long-term debt issues, protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. In MayAs of September 30, 2010, FirstEnergy terminatedno fixed-for-floating interest rate swap agreements were outstanding.
Total unamortized gains included in long-term debt associated with a notional value of $3.15 billion, which resulted in cash proceeds of $43.1 million. These proceeds will be amortized to earnings over the life of the underlying debt.
Effective June 1, 2010, FirstEnergy executed multipleprior fixed-for-floating interest rate swap agreements with a combined notional valuetotaled $129 million ($84 million net of $3.2 billion, which essentially replacedtax) as of September 30, 2010. Based on current estimates, approximately $22 million will be amortized to interest expense during the swap agreements terminated in May of 2010. As of June 30, 2010, thenext twelve months. Reclassifications from long-term debt underlying the $3.2 billion outstanding notional amount ofinto interest rate swaps had a weighted average fixed interest rate of 6%, which the swaps have converted to a current weighted average variable rate of 4%. A hypothetical 10% increase in the interest rates associated with variable-rate debt would decrease net income by less than $1expense totaled $5 million and $7 million for the three and sixnine months ended JuneSeptember 30, 2010.
On July 16, 2010, FirstEnergy terminated these fixed-for-floating interest rate swap agreements with a notional value of $3.2 billion, which resulted in cash proceeds of $83.6 million. These proceeds will be amortized to earnings over the life of the underlying debt. While FirstEnergy currently does not have any interest rate swaps outstanding, costs associated with entering into future swap transactions may be increased as a result of the recent passage of the Dodd-Frank Wall Street Reform and Consumer Protection Act, which requires increased regulation of swaps, swap dealers and major swap participants.
Equity Price Risk
FirstEnergy provides a noncontributory qualified defined benefit pension plan that covers substantially all of its employees and non-qualified pension plans that cover certain employees. The plan provides defined benefits based on years of service and compensation levels. FirstEnergy also provides health care benefits (which include certain employee contributions, deductibles and co-payments) upon retirement to employees hired prior to January 1, 2005, their dependents, and under certain circumstances, their survivors. The benefit plan assets and obligations are remeasured annually using a December 31 measurement date or as significant triggering events occur. As of JuneSeptember 30, 2010, approximately 53%44% of the pension plan isassets are invested in equity securities and 47% is56% are invested in fixed income securities and thesecurities. The plan is currently underfunded.81% funded on an accumulated benefit obligation basis as of September 30, 2010. A decline in the value of FirstEnergy’s pension plansplan assets could result in additional funding requirements. FirstEnergy currently estimates that additional cash contributions will be required beginning in 2012. The overall actual investment result during 2009 was a gain of 13.6% compared to an assumed 9% positive return.

 

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Nuclear decommissioning trust funds have been established to satisfy NGC’s and the Utilities’ nuclear decommissioning obligations. As of JuneSeptember 30, 2010, approximately 15% of the funds were invested in equity securities and 85%85% were invested in fixed income securities, with limitations related to concentration and investment grade ratings. The equity securities are carried at their market value of approximately $275$305 million as of JuneSeptember 30, 2010. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $28$31 million reduction in fair value as of JuneSeptember 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. As of June 30,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 $3$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 JuneSeptember 30, 2010, the largest credit concentration was with AEP,J.P. Morgan Chase & Co., which is currently rated investment grade, representing 7.85%9.42% of FirstEnergy’s total approved credit risk.
OUTLOOK
State Regulatory Matters
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 credits 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 June 30, 2010 and December 31, 2009, and changes during the six months then ended:
             
  June 30,  December 31,  Increase 
Regulatory Assets 2010  2009  (Decrease) 
  (In millions) 
OE $423  $465  $(42)
CEI  468   546   (78)
TE  82   70   12 
JCP&L  801   888   (87)
Met-Ed  385   357   28 
Penelec  139   9   130 
Other  15   21   (6)
          
Total $2,313  $2,356  $(43)
          

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The following table provides information about the composition of regulatory assets as of June 30, 2010 and December 31, 2009 and the changes during the six months then ended:
             
  June 30,  December 31,  Increase 
Regulatory Assets by Source 2010  2009  (Decrease) 
  (In millions) 
Regulatory transition costs $1,153  $1,100  $53 
Customer shopping incentives  74   154   (80)
Customer receivables for future income taxes  332   329   3 
Loss on reacquired debt  49   51   (2)
Employee postretirement benefits  19   23   (4)
Nuclear decommissioning, decontamination and spent fuel disposal costs  (152)  (162)  10 
Asset removal costs  (235)  (231)  (4)
MISO/PJM transmission costs  156   148   8 
Fuel costs  385   369   16 
Distribution costs  408   482   (74)
Other  124   93   31 
          
Total $2,313  $2,356  $(43)
          
Regulatory assets that do not earn a current return totaled approximately $181 million as of June 30, 2010 (JCP&L — $43 million, Met-Ed — $131 million, Penelec — $3 million and CEI $4 million). Regulatory assets not earning a current return (primarily for certain regulatory transition costs and employee postretirement benefits) are expected to be recovered by 2014 for JCP&L and by 2020 for Met-Ed and Penelec.
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 ReliabilityFirstCorporation. All of FirstEnergy’s facilities are located within the ReliabilityFirstregion. FirstEnergy actively participates in the NERC and ReliabilityFirststakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by the ReliabilityFirstCorporation.
FirstEnergy believes that it generally is in compliance with all currently-effective and enforceable reliability standards. Nevertheless,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, ReliabilityFirstand the FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with new or amended standards cannot be determined at this time; however, 2005 amendments to the FPA provide that all prudent costs incurred to comply with the new reliability standards be recovered in rates. Still, any future inability on FirstEnergy’s part to comply with the reliability standards for its bulk power system could result in the imposition of financial penalties that could have a material adverse effect on its financial condition, results of operations and cash flows.
On December 9, 2008, a transformer at JCP&L’s Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission voltage) lines out of the Oceanview and Atlantic substations resulting in customers losing power for up to eleven hours. On March 31, 2009, the NERC initiated a Compliance Violation Investigation in order to determine JCP&L’s contribution to the electrical event and to review any potential violation of NERC Reliability Standards associated with the event. NERC has submitted first and second Requests for Information regarding this and another related matter. JCP&L is complying with these requests. JCP&L is not able to predict what actions, if any, that the NERC may take with respect to this matter.

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On August 23, 2010, FirstEnergy self-reported 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, ReliabilityFirstissued a Notice of Enforcement to investigate the incident. FirstEnergy submitted a data response to ReliabilityFirston 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). As one element of the Amended ESP, the Ohio Companies agreed not to seek an additional base distribution rate increase, subject to certain exceptions, that would be effective before January 1, 2012. Applications for rehearing of the PUCO 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.

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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. A technical conference and hearings were held in 2009 and the matter has been fully briefed. Pursuant to SB221, the PUCO has 90 days from the date of the application to determine whether the MRO meets certain statutory requirements. Although the Ohio Companies requested a PUCO determination by January 18, 2010, on February 3, 2010, the PUCO announced that its determination would be delayed. Under a determination that such statutory requirements are met, and to the extent the ESP described belowThe PUCO has not been implemented, the Ohio Companies would expect to implement the MRO.yet issued an order in this matter.
On March 23, 2010, the Ohio Companies filed an application for a new ESP. The new ESP which if approved by the PUCO, wouldwill 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;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.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. The evidentiary hearing began on April 20, 2010, at the PUCO. The Stipulation requested a decision by the PUCO by May 5, 2010. On April 28, 2010, the PUCO Chairman issued a statement that the PUCO would not issue a decision on May 5, 2010, and would take additional time to review the case record. FirstEnergy recorded approximately $39.5 million of regulatory asset impairments and expenses related to the ESP. On May 12, 2010, a supplemental stipulation was filed that added two additional parties to the Stipulation, namely the City of Akron, Ohio and Council for Smaller Enterprises, to provide additional energy efficiency benefits. Pursuant to a PUCO Entry, a hearing was held on June 21, 2010 to consider the estimated bill impacts arising from the proposed ESP, and testimony was provided in support of the supplemental stipulation. On July 22, 2010, a second supplemental stipulation was filed that, among other provisions and if approved, would provideprovides a commitment that retail customers of the Ohio Companies will not pay certain costs related to the companies’ integration into PJM, a regional transmission organization, for the longer of the five year period from June 1, 2011 through May 31, 2016 or when the amount of costs avoided by customers for certain types of products totals $360 million 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. A hearingThe 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 heldfiled 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 second supplemental stipulation on July 29, 2010. The matter is awaiting decision fromsubstance of the PUCO.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 PUCO may amend these benchmarks in certain, limited circumstances, and the Ohio Companies filed an application with the PUCO seeking such amendments.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 CompaniesCompanies’ 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.

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Additionally under SB221, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they serveserved in 2009. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RFPs sought RECs, including solar RECs and RECs generated in Ohio in order to meet the Ohio Companies’ alternative energy requirements as set forth in SB221 for 2009, 2010 and 2011. The RECs acquired through these two RFPs will bewere 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’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. OnIn July 1, 2010, the Ohio Companies announced their intent to conductinitiated an additional RFP in 2010 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, bids are duecontracts were executed in August 3, 2010 and contracts are expected to be signed the week of August 9, 2010.
On February 12, 2010, OE and CEI filed an application with the PUCO to establish a new credit for all-electric customers. On March 3, 2010, the PUCO ordered that rates for the affected customers be set at a level that will provide bill impacts commensurate with charges in place on December 31, 2008 and authorized the Ohio Companies to defer incurred costs equivalent to the difference between what the affected customers would have paid under previously existing rates and what they pay with the new credit in place. Tariffs implementing this new credit went into effect on March 17, 2010. On April 15, 2010, the PUCO issued a Second Entry on Rehearing that expanded the group of customers to which the new credit would apply and authorized deferral for the associated additional amounts. The PUCO also stated that 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. No hearing has been scheduled in this matter.
As noted above in Note 8, FirstEnergy, CEI and OEOn September 9, 2010, the OCC filed a motion to dismissrequesting that a class action lawsuitprocedural schedule be established. The Ohio Companies filed their motion contra on September 23, 2010. The PUCO Staff issued a report related to the PUCO approved reductionall-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 discount that had previously been in place for residential customers with electric heating, electric water heating, or load management systems. The court has not yet ruled on that motionlonger term solution, but it made no specific recommendation to dismiss.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. TheOn July 29, 2010, the parties to the proceeding have reachedfiled a settlementJoint 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 filed a joint petitionretail market issues. The PPUC’s approval of the Joint Petition is conditioned by holding that the provision relating to approve the settlement agreement in July 2010. The PPUC is requiredrecovery 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 issue an order on the plan no later than November 8, 2010. Ifapproval of cost recovery by FERC. Penn may not put these provisions into effect until FERC has approved procurement under the planrecovery and allocation of MISO exit fees and PJM integration costs. An Order consistent with the Motion is expected to begin January 2011.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 loss costs.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.

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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 April 2, 2010, Met-Ed and Penelec filed a Response to the PPUC’s March 3, 2010 Order requesting approval of procedures to establish separate accounts to track all marginal transmission loss revenues and related interest and the use of those funds to mitigate future generation rate increases commencing January 1, 2011, and the PPUC entered an Order on June 7, 2010, granting Met-Ed’s and Penelec’s request. On July 9, 2010, Met-Ed and Penelec filed their briefs with the Commonwealth Court of Pennsylvania. The Office of Small Business Advocate filed its brief on July 9, 2010. The PPUC’sOn August 24, 2010, the PPUC as well as MEIUG and PICA filed their briefs. Met-Ed and Penelec filed their reply brief is due to be filed in Auguston 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 be fully recoveredprovide 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 rollinclude smart meter costs intoin base rates.
Legislation addressing rate mitigation 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 the expiration of rate caps was introducedPenn from seeking to include smart meter costs in the legislative session that ended in 2008; several bills addressing these issues were introduced in the 2009 legislative session. The final form and impact of such legislation is uncertain.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 JuneSeptember 30, 2010, the accumulated deferred cost balance totaledwas a credit of approximately $81$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.

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In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004, supporting continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The DPA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. JCP&L responded to additional NJBPU staff discovery requests in May and November 2007 and also submitted comments in the proceeding in November 2007. A schedule for further NJBPU proceedings has not yet been set. On March 13, 2009, JCP&L filed its annual SBC Petition with the NJBPU that includes a request for a reduction in the level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009 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, the FERC issued an order (Opinion 494) finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate based on the amount of load served in a transmission zone. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a load flow methodology referred to as “DFAX”(DFAX), which is generally referred to as a “beneficiary pays” approach to allocating the cost of high voltage transmission facilities. The FERC found that PJM’s current beneficiary-pays cost allocation methodology was not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff. FERC ultimately issued an order approving use of the beneficiary pays method of cost allocation for transmission facilities included in the PJM regional plan that operate below 500 kV.
The FERC’s April 19, 2007Opinion 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 within 45 days, and the reply comments 30 days later.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 not expected to act before the fourth quarterend of 2010.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. Most of FirstEnergy’s transmission assets in Pennsylvania and all ofIn the transmission assets in New Jersey already operate as a part of PJM.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.
InOn 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, and the Ohio Companies and Penn’s loadPenn to movingthe move into PJM on the schedule described in the application and approved in the FERC Order.PJM.
FirstEnergy successfully conducted the FRR auctions on March 19, and2010. Moreover, the ATSI-zone loads participated in the PJM base residual auction for the 2013 delivery year, thereby obtainingyear. Successful completion of these steps secured the capacity necessary for itsthe ATSI footprint to meet PJM’s capacity requirements. FirstEnergy expects to integrate into PJM effective June 1, 2011.
On September 4, 2009, the PUCO opened a case to take comments from Ohio’s stakeholders regarding the RTO consolidation. Several parties have intervened inOn August 25, 2010, the regulatory dockets at the FERC and at the PUCO. Certain interveners have commented and protested particular elements of the proposed RTO consolidation, including an exit fee to MISO, integration costs to PJM, and cost-allocations of future transmission upgrades in PJM and MISO.
MISO Complaints Versus PJM
On March 9, 2010, MISO filed two complaints against PJM with FERC under Sections 206, 306 and 309 of the FPA alleging violations of the MISO/PJM Joint Operating Agreement (JOA). In Docket EL 10-46-000, the complaint alleges that PJM erroneously calculated charges to MISO for market-to-market settlements made from 2005 to 2009 pursuant to the congestion management provisions of the JOA. The MISO seeks approximately $130 million plus interest to correct for resultant net underpayments from PJM to MISO. In Docket No.EL10-45-000, MISO alleges that by failing to account for the market flows from 34 PJM generators over the period from 2007-2009, PJM underpaid MISO by a total of roughly $75 million including interest. For the period from 2005-2007, MISO claimed an underpayment by PJM of at least $12 million plus interest. MISO also claimed that PJM failed to maintain required records necessary to calculate underbilling for the 2005-2007 billing.
In the second complaint, MISO alleged that PJM has refused to comply with provisions of the JOA requiring market-to-market dispatch since 2009, and is improperly demanding repayment of redispatch payments previously made to MISO. PJM filed its answers to the complaints on April 12, 2010, opposing the relief sought by MISO.
In addition, on April 12, 2010, PJM filed a complaint with FERC pursuant to Section 206, 306, and 309 alleging that MISO is violating the JOA with PJM by initiating market-to-market coordination and financial settlements for substitute (proxy) reciprocal coordinated flowgates between MISO and PJM. PJM claims that the JOA does not permit MISO to initiate market-to-market settlements using proxy flowgates in lieu of designated reciprocal coordinated flowgates. This complaint addresses substantially the same issues as the second MISO complaint, in which MISO argues that the use of proxy flowgates is permitted by agreement of the RTOs and operating practice. Each party filed a complaint in order to ensure their right to claim refunds, if any, if successful in their arguments at FERC.
On June 29, 2010, FERCPUCO issued an order consolidatingthat, among other things, committed the casesPUCO to close this case and establishing settlement judge procedures. Ifalso to withdraw its objections that were filed in the settlement process is unsuccessful,relevant FERC dockets conditioned upon the casesOhio 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 proceedbe resolved in future FERC proceedings. Under the terms of the ESP order issued August 25, 2010, the PUCO has agreed to evidentiary hearings. FirstEnergy is unable to predict the outcome ofclose this matter.docket.
MISO Multi-Value Project Rule Proposal
On July 15, 2010, MISO and certain MISO transmission owners jointly filed with the FERC their proposed cost allocation methodology for new transmission projects. If approved, so-called Multi ValueThe new transmission projects—described as Multi-Value Projects (MVPs)— transmission projects that haveare a regional impact and are partclass of MTEP projects. The MISO proposes to allocate the costs of MVPs by means of a regional plan —usage-based charge that will have a 100% regional allocationbe 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 costs under the proposed methodology. If approved by FERC, MISO’sMISO. MISO expects that its MVP proposal is expected to permit the allocation ofwill fund the costs of large transmission projects designed to integratebring wind generation from the upper Midwest acrossto load centers in the entire MISO.east. MISO has requested athat FERC response to the filingrule on its MVP proposal by the FERC’s December, open meeting, 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.

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CAA Compliance
FirstEnergy is required to meet federally-approved SO2SO2 and NOXNOX emissions regulations under the CAA. FirstEnergy complies with SO2 and NOx reduction requirements under the CAA and State Implementation Plan(s)SIP(s) under the CAA (SIPs) by burning lower-sulfur fuel, combustion controls and post-combustion controls, generating more electricity from lower-emitting plants and/or using emission allowances. Violations 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 in the U.S. District Court for the Western District of Pennsylvania also 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 ReliantRRI Energy, Inc. (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU and Met-Ed. Specifically, these suits allege that “modifications” at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR or permitting underin violation of the CAA’s PSD program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. 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 underin violation of the CAA’s PSD program. In May 2010, the EPA issued a second NOV to Mission Energy Westside, Inc., Penelec, NYSEGNew 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 scheduled 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.

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National Ambient Air Quality Standards
The EPA’s CAIR requires reductions of NOXNOX and SO2 emissions in two phases (2009/2010 and 2015), ultimately capping SO2 emissions in affected states to 2.5 million tons annually and NOXNOX emissions to 1.3 million tons annually. In 2008, the U.S. Court of Appeals for the District of Columbia vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” In December 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s opinion. The Court ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOX“NOX SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the “8-hour” ozone NAAQS. In July 2010, the EPA proposed the Clean Air Transport Rule (CATR) to replace CAIR, which remains in effect until the EPA finalizes CATR. CATR requires reductions of NOXNOX and SO2 emissions in two phases (2012 and 2014), ultimately capping SO2 emissions in affected states to 2.6 million tons annually and NOXNOX emissions to 1.3 million tons annually. The EPA proposed a preferred regulatory approach that allows trading of NOXNOX and SO2 emission allowances between power plants located in the same state with severeand severely limits on interstate trading of NOx and SO2 emission allowances. The EPA also requested comment on two alternative approaches—the first eliminates interstate trading of NOXNOX and SO2 emission allowances and the second eliminates trading of NOXNOX and SO2 emission allowances in its entirety. Depending on the actions taken by the EPA with respect to CATR, the proposed MACT regulations discussed below and any future regulations that are ultimately implemented, FGCO’s future cost of compliance may be substantial. Management is currently assessing the impact of these environmental proposals and other factors on FCGO’sFGCO’s facilities, particularly on the operation of its smaller, non-supercritical units. For example, as disclosed herein, management may decidedecided to idle certain of these 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. The EPA entered into a consent decree requiring it to propose maximum achievable control technology (MACT) regulations for mercury and other hazardous air pollutants by March 16, 2011, and to finalize the regulations by November 16, 2011. On April 29, 2010, the EPA issued proposed MACTmaximum 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.
Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap-and-trade approach as in the CAMR, but rather follows a command-and-control approach imposing emission limits on individual sources. On December 23, 2009, the Supreme Court of Pennsylvania affirmed the Commonwealth Court of Pennsylvania ruling that Pennsylvania’s mercury rule is “unlawful, invalid and unenforceable” and enjoined the Commonwealth from continued implementation or enforcement of that rule.
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.
The EPA has authority under the CAA to regulate “air pollutants” from electric generating plants and other facilities. 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 GHGGHGs increase the threat of climate change.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 willwould 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 CAACAA’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 Prevention of Significant Determination (PSD)PSD program, but until July 1, 2011 that emissions applicability threshold will only apply if PSD is triggered by non-carbon dioxide pollutants.

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At the international level, the Kyoto Protocol, signed by the U.S. in 1998 but never submitted for ratification by the U.S. Senate, was intended to address global warming by reducing the amount of 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, includedCelsius; 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 2020,2020; and establishedestablish 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,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, should the court of appeals decision be affirmed or not subjected to further review, FirstEnergy and/or one or more of its subsidiaries could be named in actions making similar allegations.
FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO2 emissions per KWH of electricity generated by FirstEnergy is lower than many regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy’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.

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On December 30, 2009, in an advanced notice of public rulemaking, the EPA said that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. On May 4, 2010, the EPA proposed two options for additional regulation 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 JuneSeptember 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 JuneSeptember 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. Early in 2010, the Appellate Division heard oral argument on plaintiff’s appeal of the trial court’s decision decertifying the class, and onOn 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 15)16), purported shareholders of Allegheny Energy have filed putative shareholder class action and/or derivative lawsuits in Pennsylvania and Maryland state courts, as well as in the U.S. District Court for the Western District of Pennsylvania, against Allegheny Energy and its directors and certain officers, referred to as the Allegheny Energy defendants, FirstEnergy and Merger Sub. 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. Additional details about the actions are provided below. While FirstEnergy believes the lawsuits are without merit and has defended vigorously against the claims, in order to avoid the costs associated with the litigation, the defendants have agreed to the terms of a disclosure-based settlement of the lawsuits. The defendantsall these shareholder lawsuits and have reached an agreement with counsel for all of the plaintiffs concerning fee applications, but aapplications. Under the terms of the settlement, no payments are being made by FirstEnergy or Merger Sub. A formal stipulation of settlement has not yet beenwas filed with any court.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.
Four putative class action and derivative lawsuits were filed in the Circuit Court for Baltimore City, Maryland. One was withdrawn. The court consolidated the three cases under the captionOakmont Capital Management, LLC v. Evanson, et al., C.A. No. 24-C-10-1301, and appointed Lewis M. Lynn as Lead Plaintiff. Plaintiff Lynn filed a Consolidated Amended Complaint on April 12, 2010. On April 21, 2010, defendants filed Motions to Dismiss the Consolidated Amended Complaint for failure to state a claim. The court has stayed all discovery pending resolution of those motions. The court also has entered a stipulated order certifying a class with no opt-out rights. On May 27, 2010, the parties reported to the court that they have agreed to the terms of a disclosure-based settlement and requested that the court cancel the oral argument on the motions to dismiss that had been scheduled for June 3, 2010. On May 28, 2010, the court removed the hearing from its calendar.

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Three shareholder lawsuits were filed in the Court of Common Pleas of Westmoreland County, Pennsylvania, raising putative class action and derivative claims against the Allegheny Energy directors and officers, FirstEnergy and Allegheny Energy. The court has consolidated these actions under the caption,In re Allegheny Energy, Inc. Shareholder Class and Derivative, Litigation, Lead Case No. 1101 of 2010, and appointed lead counsel. On April 5, 2010, the Allegheny Energy defendants filed a Motion to Stay the Proceedings. Shortly thereafter, FirstEnergy similarly filed a Motion to Stay. Plaintiffs filed a Motion for Expedited Discovery. The court scheduled a hearing on the motions for May 27, 2010. On May 21, 2010, plaintiffs filed a Verified Consolidated Shareholder Derivative and Class Complaint. On May 26, 2010, the parties filed a Motion for a Continuance of the May 27 hearing, which the court granted. On June 1, 2010, the parties reported to the court that they have agreed to the terms of a disclosure-based settlement.
A putative shareholder lawsuit styled as a class action was filed in the U.S. District Court for the Western District of Pennsylvania and is captionedLouisiana Municipal Police Employees’ Retirement System v. Evanson, et al., C.A. No. 10-319 NBF. On June 1, 2010, the parties reported to the court that they have agreed to the terms of a disclosure-based settlement.
Nuclear Plant Matters
During a planned refueling outage that began on February 28, 2010, FENOC conducted a non destructive examination and testing of the Control Rod Drive Mechanism (CRDM) Nozzlesnozzles 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 JuneSeptember 30, 2010, FirstEnergy had approximately $1.9$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. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy providedprovides an additional $80$15 million parental guarantee associated with the funding of decommissioning costs for these units and indicated that it planned to contribute an additional $80 million to these trusts by 2010. By a letter dated March 8, 2010, primarily as a result of the Beaver Valley Power Station operating license renewal, FENOC requested that the NRC reduce FirstEnergy’s parental guarantee to $15 million and notified the staff that it no longer planned to make the additional contributions into the trusts. By a letter dated July 14, 2010, the NRC stated that it had no objection to the reduction in the parental guarantee.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 April 14, 2010, JCP&L reached an agreement on a settlement package with its bargaining unit employees regarding a grievance challenging JCP&L’s 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. The agreement included an agreed-upon settlement amount and extension of the collective bargaining agreement. On July 22, 2010, the court signed an order approving and implementing the parties’ agreement. As of June 30, 2010, JCP&L reduced its reserve to $9 million for the settlement which will be paid to the employees over the next thirty days beginning on July 25, 2010. The collective bargaining agreement extension is also effective as of July 25, 2010.

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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 has not yet ruled on thatgranted the motion to dismiss. The named-defendant companies will continue to defend these claims including challenging any class certification.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 1011 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’ revenues also includeFES sales to non-affiliated customersare concentrated in Ohio, Pennsylvania, New Jersey,Illinois, Maryland, Michigan Illinois and Maryland.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 $254$491 million in the first sixnine months of 2010, compared to the same period of 2009. The decrease was primarily due to higher purchased power costs,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 increased fuel and interest expense, partially offset by higher revenues and investmenta decrease in sales margins also contributed to the decline in net income.
Revenues
Total revenues, excludingExcluding the impact of the 2009 gain on the OVEC sale, total revenues increased $388$836 million in the first sixnine 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:
                        
 Six Months    Nine Months   
 Ended June 30 Increase  Ended September 30 Increase 
Revenues by Type of Service 2010 2009 (Decrease)  2010 2009 (Decrease) 
 (In millions)  (In millions) 
Direct and Government Aggregation $1,097 $174 $923  $1,814 $406 $1,408 
POLR 1,260 1,732  (472) 1,911 2,369  (458)
Wholesale 186 311  (125)
Other Wholesale 322 503  (181)
Transmission 36 41  (5) 58 57 1 
RECs 67 — 67  67 — 67 
Sale of OVEC participation interest — 252  (252) — 252  (252)
Other 57 57 —  84 85  (1)
              
Total Revenues
 $2,703 $2,567 $136  $4,256 $3,672 $584 
              
The increase in direct and government aggregation revenues of $923$1,408 million resulted from increased revenue in both the MISO and PJM markets. The increase in revenue primarily resulted from the acquisition of new commercial and industrial customers, as well as new government aggregation contracts with communities in Ohio that provideprovided generation to approximately 1.11.2 million residential and small commercial customers at the end of JuneSeptember 2010 compared to approximately 21,000500,000 such customers at the end of JuneSeptember 2009, partially offset by lower unit prices. During January 2010, FES began supplying powerIn addition, sales to approximately 425,000 NOPEC customers.residential and small commercial customers were bolstered by weather in the delivery area that was 69% warmer than in 2009.

 

10399

The decrease in POLR revenues of $472$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 tofrom 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.
WholesaleOther wholesale revenues decreased $125$181 million due to reduced volumes reflecting market declines 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  Increase 
Source of Change in Direct and Government Aggregation (Decrease)  (Decrease) 
 (In millions)  (In millions) 
Direct Sales:  
Effect of increase in sales volumes $633  $909 
Change in prices  (47)  (73)
      
 586  836 
      
Government Aggregation  
Effect of an increase in sales volumes 337 
Effect of increase in sales volumes 570 
Change in prices —  2 
      
 337  572 
      
Net Increase in Direct and Gov’t Aggregation Revenues
 $923  $1,408 
      
    
     Increase 
Source of Change in Wholesale Revenues (Decrease)  (Decrease) 
 (In millions)  (In millions) 
POLR:  
Effect of 15.1% decrease in sales volumes $(262)
Effect of decrease in sales volumes $(200)
Change in prices  (210)  (258)
      
  (472)  (458)
      
Wholesale: 
Effect of 56.7% decrease in sales volumes  (123)
Other Wholesale: 
Effect of decrease in sales volumes  (147)
Change in prices  (2) (34)
      
  (125)  (181)
      
Decrease in Wholesale Revenues
 $(597)
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 decreased $5increased $1 million due primarily to higher MISO congestion revenue, offset by lower PJM congestion revenue.
Expenses
Total expenses increased $539 million$1.2 billion in the first sixnine months of 2010, compared with the same period of 2009.

100

The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first sixnine months of 2010, from the same period last year:
        
 Increase  Increase 
Source of Change in Fuel and Purchased Power (Decrease)  (Decrease) 
 (In millions)  (In millions) 
Fossil Fuel:  
Change due to increased unit costs $33  $30 
Change due to volume consumed 40  135 
      
 73  165 
      
Nuclear Fuel:  
Change due to increased unit costs 18  23 
Change due to volume consumed 3  3 
      
 21  26 
      
Non-affiliated Purchased Power:  
Power contract mark-to-market adjustment 17  43 
Change due to decreased unit costs  (98)  (84)
Change due to volume purchased 484  650 
      
 403  609 
      
Affiliated Purchased Power:  
Change due to decreased unit costs  (4)
Change due to increased unit costs 81 
Change due to volume purchased 19  15 
      
 15  96 
      
Net Increase in Fuel and Purchased Power Costs
 $512  $896 
      

104

Fossil fuel costs increased $73$165 million in the first sixnine 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 sixnine 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 sixnine months of 2010, compared to the same period last year. Nuclear fuel costs increased $21$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 $403$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 due to the Perry nuclear refueling outage in 2009.companies.
Other operating expenses increased $23$25 million in the first sixnine months of 2010, compared to the same period of 2009, primarily due to increased transmission expenses ($3336 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, ($19 million), 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 ($37 million).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 $4$5 million due to sales taxes associated with increased revenues.
Other Expense
Total other expense decreased $2increased $128 million in the first sixnine months of 2010, compared to the same period of 2009, primarily due to a $36 million increasedecrease in investment income resulting from more favorable performance of nuclear decommissioning trust investments, partially offset by a $31 millioninvestment 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 in the second half of 2009 combined with the restructuring of existing long-term debt.PCRBs.

 

105101

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 $28$40 million in the first sixnine 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.revenues and investment income.
Revenues
Revenues decreased $473$589 million, or 33.3%29%, in the first sixnine months of 2010, compared with the same period in 2009, due primarily to a decrease in generation revenues. Distribution revenues also were lower than they were in the first half of 2009.
Retail generation revenues decreased $438$584 million primarily due to a decrease in KWH sales in all customer classes, partially offset by higher average prices in the commercial and industrial classes. Lower KWH sales were primarily the result of a 46.1%42% increase in customer shopping in the first sixnine 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 sixnine months of 2010, reflecting a 62%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 sixnine months of 2010, compared to the same period in 2009, are summarized in the following tables:
     
Retail Generation KWH Sales Decrease 
     
Residential  (30.326.0)%
Commercial  (60.0)%
Industrial  (64.362.7)%
    
Decrease in Retail Generation Sales
  (48.145.7)%
    
        
Retail Generation Revenues Decrease  Decrease 
 (In millions)  (In millions) 
Residential $(143) $(166)
Commercial  (167)  (236)
Industrial  (128)  (182)
      
Decrease in Retail Generation Revenues
 $(438) $(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 $17$1 million in the first sixnine months of 2010, compared to the same period in 2009, due to lower commercial and industrial revenues, partially offset by higher residential revenues. Commercial and industrial revenues were primarily impacted by lower average unit prices, resulting from lower transmission rates in 2010. Residential distribution revenues were higher due to higher average unit prices resulting from the 2009 ESP and slightly higher KWH deliveries resulting from the warmer conditions described above. Increased industrial deliveries were the result of improving economic conditions, reflecting an increase in KWH deliveries to major steel customers (36%(42%) and automotive customers (27%(25%)., reflecting improving economic conditions.

 

106102

Changes in distribution KWH deliveries and revenues in the first sixnine months of 2010, compared to the same period in 2009, are summarized in the following tables:
     
Distribution KWH Sales Increase 
     
Residential  0.26.3%
Commercial  0.72.1%
Industrial  12.710.6%
    
Increase in Distribution Deliveries
  4.06.2%
    
     
  Increase 
Distribution Revenues (Decrease) 
  (In millions) 
Residential $9 
Commercial  (8)
Industrial  (18)
    
Net Decrease in Distribution Revenues
 $(17)
    
Wholesale revenues decreased $11 million primarily due to lower unit prices, partially offset by an increase in sales to FES from OE’s leasehold interests in Perry Unit 1 and Beaver Valley Unit 2.
     
  Increase 
Distribution Revenues (Decrease) 
  (In millions) 
Residential $27 
Commercial  (9)
Industrial  (19)
    
Net Decrease in Distribution Revenues
 $(1)
    
Expenses
Total expenses decreased $521$674 million in the first sixnine months of 2010, from the same period of 2009. The following table presents changes from the prior period by expense category:
        
Expenses — Changes (Decrease) 
 Increase 
Expenses - Changes (Decrease) 
 (In millions)  (In millions) 
Purchased power costs $(422) $(564)
Other operating expenses  (93)  (100)
Amortization of regulatory assets, net  (4)  (11)
General taxes  (2) 1 
      
Decrease in Expenses
 $(521)
Net Decrease in Expenses
 $(674)
      
Purchased power costs decreased in the first sixnine 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 sixnine months of 2010 and slightly lower unit costs. The decrease in other operating costs for the first sixnine months of 2010, was primarily due to lower MISO transmission expenses ($48 million) (assumed by third party suppliers beginning June 1, 2009) and the absence in 2010 of $18 million oflower costs incurred in the first six months of 2009 associated with regulatory obligations for economic development and energy efficiency programs under OE’s 2009 ESP. LowerESP ($18 million). The amortization of net regulatory assets wasdecreased primarily due to lower amortization of deferred MISO transmission costs,cost amortization, partially offset by the recovery of certain regulatory assets that beganassets.
Other Expense
Other expense increased $21 million in 2010. The decrease in general taxes wasthe first nine months of 2010, compared to the same period of 2009, primarily due to lower Ohio KWH taxes and lower property taxes.nuclear decommissioning trust investment income.

 

107103

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 $94$93 million in the first sixnine months of 2010, compared to the same period of 2009. The increase in earnings was primarily due to the absence in 2010 of one-time regulatory charges recognized in 2009, and decreased purchased power and other operating costs, partially offset by decreased revenues and deferred regulatory assets.
Revenues
Revenues decreased $299$406 million, or 32%30%, in the first sixnine 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 SalesIncrease
Residential7.3%
Commercial2.4%
Industrial14.4%
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 $200$321 million in the first sixnine months of 2010, compared to the same period of 2009, primarily due to lower KWH sales across all customer classes, partially offset by higher average unit prices in all customer classes. Reduced KWH sales were primarily the result of increased customer shopping in the first sixnine 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 usageKWH deliveries resulting from the warmer weather conditions described above. Decreased volumes were partially offset by higher average unit prices in the first six months of 2010, reflecting a 113% increase in cooling degree days.all customer classes. Retail generation prices increased in 2010 as a result of the CBP auction for the service period beginning June 1, 2009.

104

Changes in retail generation sales and revenues in the first sixnine months of 2010, compared to the same period of 2009, are summarized in the following tables:
     
Retail Generation KWH Sales Decrease 
     
Residential  (54.351.7)%
Commercial  (68.569.4)%
Industrial  (49.247.4)%
    
Decrease in Retail Generation Sales
  (55.654.2)%
    
     
Retail Generation Revenues Decrease 
  (In millions) 
Residential $(50)
Commercial  (80)
Industrial  (70)
    
Decrease in Retail Generation Revenues
 $(200)
    
Distribution revenues decreased $91 million in the first six months of 2010, compared to the same period of 2009, due to lower average unit prices for all customer classes and decreased KWH deliveries in the residential sector, partially offset by increased KWH deliveries in the industrial and commercial sectors. The lower average unit prices were the result of lower transition rates in 2010. Increased industrial deliveries were the result of improving economic conditions, reflecting an increase in KWH deliveries to major steel customers (158%) and automotive customers (14%).

108

Changes in distribution KWH deliveries and revenues in the first six months of 2010, compared to the same period of 2009, are summarized in the following tables:
Increase
Distribution KWH Sales(Decrease)
Residential(0.6)%
Commercial1.7%
Industrial12.0%
Net Increase in Distribution Deliveries
5.1%
        
Distribution Revenues Decrease 
Retail Generation Revenues Decrease 
 (In millions)  (In millions) 
Residential $(13) $(78)
Commercial  (28)  (126)
Industrial  (50)  (117)
      
Decrease in Distribution Revenues
 $(91)
Decrease in Retail Generation Revenues
 $(321)
      
Expenses
Total expenses decreased $452$561 million in the first sixnine months of 2010, compared to the same period of 2009. The following table presents the change from the prior period by expense category:
        
 Increase  Increase 
Expenses — Changes (Decrease) 
Expenses - Changes (Decrease) 
 (In millions)  (In millions) 
Purchased power costs $(325) $(441)
Other operating costs  (44)  (45)
Amortization of regulatory assets, net  (210)  (205)
Deferral of new regulatory assets 135  135 
General taxes  (8)  (5)
      
Net Decrease in Expenses
 $(452) $(561)
      
Purchased power costs decreased in the first sixnine 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 sixnine 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 sixnine months of 2010, primarily due to a 2010 favorable tax settlement in Ohio.
Other Expense
Other expense increased $4 million in the first sixnine months of 2010, compared to the same period of 2009 due primarily to lower investment income and higher interest expense associated with the August 2009 issuance of $300 million first mortgage bonds, partially offset by the November 2009 redemption of $150 million senior secured notes.income.

 

109105

THE TOLEDO EDISON COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
TE is a wholly owned electric utility subsidiary of FirstEnergy. TE conducts business in northwestern Ohio, providing regulated electric distribution services. TE also procures generation services for those customers electing to retain TE as their power supplier.
For additional information with respect to TE, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Earnings available to parent increased by $7$13 million in the first sixnine months of 2010, compared to the same period of 2009. The increase was primarily due to decreased net amortization of regulatory assets, purchased power and other operating costs, partially offset by an increase in interest expense and decreases in revenues and investment income.
Revenues
Revenues decreased $218$287 million, or 46%42%, in the first sixnine 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 SalesIncrease
Residential9.8%
Commercial2.2%
Industrial15.5%
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 $203$282 million in the first sixnine months of 2010, compared to the same period of 2009, primarily due to lower KWH sales across all customer classes and lower unit prices to industrial customers. Lower KWH sales to all customer classes were primarily the result of a 63%59% increase in customer shopping in the first sixnine 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 arewere 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.

106

Changes in retail generation KWH sales and revenues in the first sixnine months of 2010, compared to the same period of 2009, are summarized in the following tables:
     
Retail Generation KWH Sales Decrease 
     
Residential  (48.645.1)%
Commercial  (72.372.5)%
Industrial  (60.859.4)%
    
Decrease in Retail Generation Sales
  (60.559.0)%
    
        
Retail Generation Revenues Decrease  Decrease 
 (In millions)  (In millions) 
Residential $(44) $(57)
Commercial  (72)  (104)
Industrial  (87)  (121)
      
Decrease in Retail Generation Revenues
 $(203) $(282)
      
DistributionWholesale revenues decreased $26increased $14 million in the first six months of 2010, compared to the same period of 2009, primarily due to lower unit prices in all customer classes, partially offset by increased KWH deliveries to industrial customers. Lower unit prices are primarily due to lower transmission rates. Increased industrial deliveries were the result of improving economic conditions, reflecting an increase in KWH deliveries to major automotive customers (36%) and steel customers (37%).

110

Changes in distribution KWH deliveries and revenues in the first six months of 2010, compared to the same period of 2009, are summarized in the following tables:
Increase
Distribution KWH Deliveries(Decrease)
Residential(0.4)%
Commercial(1.6)%
Industrial14.8%
Net Increase in Distribution Deliveries
6.2%
     
Distribution Revenues Decrease 
  (In millions) 
Residential $(5)
Commercial  (6)
Industrial  (15)
    
Decrease in Distribution Revenues
 $(26)
    
Wholesale revenues increased $7 million in the first sixnine months of 2010, compared to the same period of 2009, primarily due to higher revenues from sales to NGC from TE’s leasehold interest in Beaver Valley Unit 2.
Expenses
Total expenses decreased $241$328 million in the first sixnine months of 2010, compared to the same period of 2009. The following table presents changes from the prior period by expense category:
     
Expenses — Changes Decrease 
  (In millions) 
Purchased power costs $(179)
Other operating costs  (29)
Amortization of regulatory assets, net  (32)
General taxes  (1)
    
Decrease in Expenses
 $(241)
    
     
  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 $179 million in the first sixnine months of 2010, compared to the same period of 2009, due to lower volume as a result of decreased KWH sales requirements. Other operating costs decreased $29 million primarily due to reduced transmission expense (assumed by third party suppliers beginning June 1, 2009), lower costs associated with regulatory obligations for economic development and energy efficiency programs and decreased labor expenses. The $32 million decrease in netamortization of regulatory asset amortization wasassets decreased primarily due to PUCO-approved cost deferrals and lower MISO transmission cost amortization partially offset by the absence of MISO transmission and fuel cost deferrals in the first sixnine months of 2010, compared to the same period of 2009.
Other Expense
Other expense increased $13$17 million in the first sixnine 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.

 

111107

JERSEY CENTRAL POWER & LIGHT COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
JCP&L is a wholly owned, electric utility subsidiary of FirstEnergy. JCP&L conducts business in New Jersey, providing regulated electric transmission and distribution services. JCP&L also procures generation services for franchise customers electing to retain JCP&L as their power supplier. JCP&L procures electric supply to serve its BGS customers through a statewide auction process approved by the NJBPU.
For additional information with respect to JCP&L, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Net income increased by $13$34 million in the first sixnine 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 lower revenues and increased other operating costs.
Revenues
In the first sixnine months of 2010, revenues decreased $57increased $43 million, or 4%2%, compared to the same period of 2009. The decreaseincrease 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 wholesale generation revenues,improved economic conditions in JCP&L’s service territory. Decreased composite unit prices in the commercial and industrial classes partially offset by higherthe increased volume.
Changes in distribution KWH deliveries and transmission revenues.revenues in the first nine months of 2010 compared to the same period of 2009 are summarized in the following tables:
Distribution KWH SalesIncrease
Residential10.6%
Commercial2.9%
Industrial3.0%
Increase in Distribution Deliveries
6.3%
     
Distribution Revenues Increase 
  (In millions) 
Residential $58 
Commercial  5 
Industrial  — 
    
Increase in Distribution Revenues
 $63 
    
Retail generation revenues decreased $73$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 105%60% increase in cooling degree days.days during the first nine months of 2010.

108

Changes in retail generation KWH sales and revenues in the first sixnine months of 2010, compared to the same period of 2009, are summarized in the following tables:
     
  Increase 
Retail Generation KWH Sales (Decrease) 
     
Residential  5.110.1%
Commercial  (31.027.7)%
Industrial  (24.721.4)%
    
Net Decrease in Retail Generation Sales
  (10.15.0)%
    
        
 Increase  Increase 
Retail Generation Revenues (Decrease)  (Decrease) 
 (In millions)  (In millions) 
Residential $30  $81 
Commercial  (95)  (127)
Industrial  (8)  (8)
      
Net Decrease in Retail Generation Revenues
 $(73) $(54)
      
Wholesale generation revenues decreased $7increased $22 million in the first six months of 2010, compared to the same period of 2009; less power was available for sale due to the termination of a NUG power purchase contract in July 2009.
Distribution revenues increased $17 million in the first sixnine months of 2010, compared to the same period of 2009, due primarily to higher KWH deliveries in all customer classes. Increased usage from warmer weather and improving economic conditions in JCP&L’s service territory was partially offset by a decrease in composite unit prices in the commercial and industrial classes.wholesale energy prices.

112

Changes in distribution KWH deliveries andOther revenues increased $8 million in the first sixnine months of 2010, compared to the same period of 2009, are summarized in the following tables:
Distribution KWH SalesIncrease
Residential5.1%
Commercial1.7%
Industrial1.1%
Increase in Distribution Deliveries
3.1%
     
  Increase 
Distribution Revenues (Decrease) 
  (In millions) 
Residential $18 
Commercial  — 
Industrial  (1)
    
Net Increase in Distribution Revenues
 $17 
    
Transmission revenues increased $4 million in the first six months of 2010, compared to the same period of 2009,primarily due to an increase in network transmission systemtransition bond revenues from PJM.as a result of higher KWH deliveries in all customer classes.
Expenses
Total expenses decreased $77$18 million in the first sixnine months of 2010, compared to the same period of 2009. The following table presents changes from the prior period by expense category:
        
 Increase  Increase 
Expenses — Changes (Decrease) 
Expenses - Changes (Decrease) 
 (In millions)  (In millions) 
Purchased power costs $(81) $(33)
Other operating costs 14  19 
Provision for depreciation 5  5 
Amortization of regulatory assets, net  (16)  (12)
General taxes 1  3 
      
Net Decrease in Expenses
 $(77) $(18)
      
Purchased power costs decreased in the first sixnine months of 2010 primarily due to the lower retail generation KWH sales requirements and the termination of a NUG contract in July 2009.requirements. Other operating costs increased in the first sixnine months of 2010 primarily due to higher tree trimming costs resulting from major storm clean up costs in JCP&L’s service territory, partially offset by a favorable labor 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 secondthird quarter of 2009. NetThe amortization of regulatory asset amortizationassets decreased in the first sixnine months of 2010 primarily due to the deferral of the 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 partial requirements wholesale power sales agreement with FES, to supply nearly 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 $3$6 million in the first sixnine 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 and amortization of net regulatory assets.expenses.
Revenues
The revenue increase of $109Revenue increased $147 million, or 13%12%, in the first sixnine months of 2010 compared to the same period of 2009, reflectedreflecting higher distribution wholesale and generation revenues, partially offset by a decrease in transmission revenues.
Distribution revenues increased $57$82 million in the first sixnine months of 2010, compared to the same period of 2009, primarily due to higher transmission rates resulting from the annual update to Met-Ed’s TSC rider effective June 1, 2009 and 2010, partially offset by lower CTC rates for the residential class. Higher KWH deliveries to commercial and 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 97%59% increase in cooling degree days in the first sixnine months of 2010, partially offset by a 10%an 11% decrease in heating degree days for the same time period.
Changes in distribution KWH deliveries and revenues in the first sixnine months of 2010, compared to the same period of 2009, are summarized in the following tables:
     
Distribution KWH Deliveries Increase 
     
Residential  0.75.0%
Commercial  4.24.4%
Industrial  4.54.0%
    
Increase in Distribution Deliveries
  2.84.6%
    
     
Distribution Revenues Increase 
  (In millions) 
Residential $23 
Commercial  21 
Industrial  13 
    
Increase in Distribution Revenues
 $57 
    
Wholesale revenues increased $40 million in the first six months of 2010 compared to the same period of 2009, primarily reflecting higher PJM capacity prices.
     
Distribution Revenues Increase 
  (In millions) 
Residential $40 
Commercial  27 
Industrial  15 
    
Increase in Distribution Revenues
 $82 
    
Retail generation revenues increased $21$36 million in the first sixnine 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 sixnine months of 2010, compared to the same period of 2009, are summarized in the following tables:
     
Retail Generation KWH Sales Increase 
     
Residential  0.75.0%
Commercial  3.72.8%
Industrial  3.51.1%
    
Increase in Retail Generation Sales
  2.43.3%
    
        
Retail Generation Revenues Increase  Increase 
 (In millions)  (In millions) 
Residential $14  $30 
Commercial 5  5 
Industrial 2  1 
      
Increase in Retail Generation Revenues
 $21  $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 $9$13 million in the first sixnine 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 $103$130 million in the first sixnine months of 2010 compared to the same period of 2009. The following table presents changes from the prior year by expense category:
        
 Increase  Increase 
Expenses — Changes (Decrease) 
Expenses - Changes (Decrease) 
 (In millions)  (In millions) 
Purchased power costs $61  $78 
Other operating costs 35  112 
Provision for depreciation 1  1 
Amortization of regulatory assets, net 8   (61)
General taxes  (2)
      
Net Increase in Expenses
 $103  $130 
      
Purchased power costs increased $61$78 million in the first sixnine months of 2010 due to an increase in unit costs and increased KWH purchased to source increased generation sales requirements. Other operating costs increased $35$112 million in the first sixnine months of 2010 compared to the same period in 2009 primarily due to higher transmission congestion expenses. The amortization of regulatory assets increased $8 million in the first six months of 2010 primarily dueand transmission loss expenses (see reference to increased transmission cost recovery. General taxes decreased $2 million mostly due to a Pennsylvania tax amnesty settlement.deferral accounting above). Depreciation expense increased $1 million due to an increase in depreciable property since JuneSeptember 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 partial requirements wholesale power sales agreement with FES, to supply nearly 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 decreasedincreased by $3$1 million in the first sixnine months of 2010, compared to the same period of 2009. The decreaseincrease was primarily due to higher purchased powerrevenues and other operating costs,net deferral of regulatory assets, partially offset by higher revenuespurchased power, other operating costs and lower amortization (deferral) of net regulatory assets and general taxes.interest expense.
Revenues
In the first sixnine months of 2010, revenues increased $50$84 million, or 6.9%7.8%, compared to the same period of 2009. The increase in revenue was primarily due to higher retail and wholesale 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 DeliveriesIncrease
Residential4.6%
Commercial4.6%
Industrial6.3%
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 $39$66 million in the first sixnine months of 2010, compared to the same period of 2009, primarily due to higher unit prices and KWH sales in all customer classes. HigherThe higher unit prices across all customer classes arewere primarily due to an increase in the generation rate, effective January 1, 2010. Higher KWH sales to commercial and industrial customers were due to improvingimproved economic conditions in Penelec’s service territory. Higher KWH sales to residential and commercial customers increased primarily due to weather-related usage, reflecting a 129%94% increase in cooling degree days in the first sixnine months of 2010, partially offset by a 10% decrease in heating degree days for the same time period.

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Changes in retail generation sales and revenues in the first sixnine months of 2010 compared to the same period of 2009 are summarized in the following tables:
     
Retail Generation KWH Sales Increase 
     
Residential  1.34.6%
Commercial  3.94.3%
Industrial  5.66.9%
    
Increase in Retail Generation Sales
  3.45.1%
    
        
Retail Generation Revenues Increase  Increase 
 (In millions)  (In millions) 
Residential $8  $17 
Commercial 17  26 
Industrial 14  23 
      
Increase in Retail Generation Revenues
 $39  $66 
      
Wholesale generation revenues increased $34$39 million in the first sixnine months of 2010, compared to the same period of 2009, due primarily to higher PJM capacity prices.
DistributionTransmission revenues decreased by $11$13 million in the first six 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.

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Changes in distribution KWH deliveries and revenues in the first six months of 2010, compared to the same period of 2009, are summarized in the following tables:
Distribution KWH DeliveriesIncrease
Residential1.3%
Commercial4.0%
Industrial5.3%
Increase in Distribution Deliveries
3.5%
     
  Increase 
Distribution Revenues (Decrease) 
  (In millions) 
Residential $6 
Commercial  (10)
Industrial  (7)
    
Net decrease in Distribution Revenues
 $(11)
    
Transmission revenues decreased by $8 million in the first sixnine 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 $45$71 million in the first sixnine months of 2010, as compared with the same period of 2009. The following table presents changes from the prior period by expense category:
        
 Increase  Increase 
Expenses — Changes (Decrease) 
Expenses - Changes (Decrease) 
 (In millions)  (In millions) 
Purchased power costs $79  $111 
Other operating costs 16  27 
Provision for depreciation 1  1 
Amortization (deferral) of regulatory assets, net  (47)  (66)
General taxes  (4)  (2)
      
Net Increase in Expenses
 $45  $71 
      
Purchased power costs increased $79$111 million in the first sixnine months of 2010, compared to the same period of 2009, primarily due to higheran increase in unit costs.costs and increased KWH purchased to source increased generation sales requirements. Other operating costs increased $16$27 million in the first sixnine months of 2010, primarily due to increased locational marginal prices partially offset by lowerhigher transmission expenses.congestion and transmission loss expenses (see reference to deferral accounting above). The amortization (deferral) of net regulatory assets decreased $47$66 million in the first sixnine 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 $4$2 million primarily due to a favorable ruling on a property tax appeal in the first quarter of 2010.
Other Expense
In the first sixnine months of 2010, other expense increased $8$14 million primarily due to an increase in interest expense on long-term debt due to thea $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 JuneSeptember 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 JuneSeptember 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.

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PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 89 and 910 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 JuneSeptember 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 secondthird quarter of 2010.
                
 Period                 
 April May June Second Quarter  Period 
  July August September Third Quarter 
Total Number of Shares Purchased(a)
 75,577 41,674 549,279 666,530  38,180 43,103 460,312 541,595 
 
Average Price Paid per Share $38.14 $36.28 $34.77 $35.24  $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
NoneSignal 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
     
Exhibit Number  
FirstEnergy
FirstEnergy
    
  2.110.1 Amendment No.1 to the AgreementAmended FirstEnergy Corp. Deferred Compensation Plan for Outside Directors, amended and Plan of Merger, datedrestated as of February 10,September 21, 2010.
   10.22010, by and amongAmended FirstEnergy Corp., Element Merger Sub, Inc. Executive Deferred Compensation Plan, amended and Alleghenyrestated as of September 21, 2010.
   10.3Energy, Inc. (incorporated by reference to FirstEnergy’s Form S-4 filed JuneSignal Peak Credit Agreement, including the forms of the guaranty and pledge agreement attached as exhibits thereto
   4, 2010, Exhibit 2.2, File No. 333-165640)
12 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 JuneSeptember 30, 2010, formatted in XBRL (eXtensible
(extensible Business Reporting Language): (i) Consolidated Statements of Income and
Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated
Statements of Cash Flows, (iv) related notes to these financial statements
tagged as blocks of text and (v) document and entity information.
    Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The
   Registrant will furnish the omitted schedules to the Securities and Exchange
FES  Commission upon request by the Commission.
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
    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
    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
    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
    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

115

    to 18 U.S.C. Section 1350
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
    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

120

   
* 
Users of thisthese 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 thisthese 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.

 

121116

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.
August 3,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  		 
 
 
Registrant		/s/ Harvey L. Wagner   
Harvey L. Wagner 
Vice President, Controller
and Chief Accounting Officer 
     
 FIRSTENERGY SOLUTIONS CORP.
JERSEY CENTRAL POWER & LIGHT COMPANY
Registrant
 		 
 /s/ K. Jon Taylor   
 RegistrantK. Jon Taylor  
OHIO EDISON COMPANY
Registrant
THE CLEVELAND ELECTRIC
ILLUMINATING COMPANY
Registrant
THE TOLEDO EDISON COMPANY
Registrant
METROPOLITAN EDISON COMPANY
Registrant
PENNSYLVANIA ELECTRIC COMPANY
Registrant
/s/ Harvey L. Wagner
Harvey L. Wagner
Vice President, Controller
and Chief Accounting Officer
JERSEY CENTRAL POWER & LIGHT COMPANY
Registrant
/s/ Kevin R. Burgess
Kevin R. Burgess
 Controller
(Principal Accounting Officer)		  

 

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