UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
(Mark One)
þQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended SeptemberJune 30, 20102011
OR
oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
oTRANSITION 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)  
333-21011 FIRSTENERGY CORP.
(An Ohio Corporation)
76 South Main Street
Akron, OH 44308
Telephone (800)736-3402 34-1843785
     
000-53742 
FIRSTENERGY SOLUTIONS CORP.
31-1560186
(An Ohio Corporation)
c/o FirstEnergy Corp.
76 South Main Street
Akron, OH 44308
Telephone (800)736-3402		 31-1560186
Telephone (800)736-3402
     
1-2578 
OHIO EDISON COMPANY
34-0437786
(An Ohio Corporation)
c/o FirstEnergy Corp.
76 South Main Street
Akron, OH 44308
Telephone (800)736-3402 34-0437786
     
1-2323 
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
34-0150020
(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 COMPANY
34-4375005
(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 COMPANY
21-0485010
(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 COMPANY
23-0870160
(A Pennsylvania Corporation)
c/o FirstEnergy Corp.
76 South Main Street
Akron, OH 44308
Telephone (800)736-3402 23-0870160
     
1-3522 
PENNSYLVANIA ELECTRIC COMPANY
25-0718085
(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 OCTOBER 22, 2010JULY 29, 2011 
FirstEnergy Corp., $10$.10 par value  304,835,407418,216,437 
FirstEnergy Solutions Corp., no par value  7 
Ohio Edison Company, no par value  60 
The Cleveland Electric Illuminating Company, no par value  67,930,743 
The Toledo Edison Company, $5 par value  29,402,054 
Jersey Central Power & Light Company, $10 par value  13,628,447 
Metropolitan Edison Company, no par value  859,500740,905 
Pennsylvania Electric Company, $20 par value  4,427,577 
FirstEnergy Corp. is the sole holder of FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company common stock.

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

 

 

Forward-Looking Statements:This Form 10-Q includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements include declarations regarding management’s intents, beliefs and current expectations. These statements typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” “believe,” “estimate” and similar words. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements.
Actual results may differ materially due to:
The speed and nature of increased competition in the electric utility industry and legislative and regulatory changes affecting how generation rates will be determined following the expiration of existing rate plans in Pennsylvania.industry.
The impact of the regulatory process on the pending matters in Ohio, Pennsylvaniathe various states in which we do business including, but not limited to, matters related to rates.
The status of the PATH project in light of PJM’s direction to suspend work on the project pending review of its planning process, its re-evaluation of the need for the project and New Jersey.the uncertainty of the timing and amounts of any related capital expenditures.
Business and regulatory impacts from ATSI’s realignment into PJM.PJM Interconnection, L.L.C.
Economic or weather conditions affecting future sales and margins.
Changes in markets for energy services.
Changing energy and commodity market prices and availability.
Financial derivative reforms that could increase our liquidity needs and collateral costs.
Replacement power costs being higher than anticipated or inadequately hedged.
The continued ability of FirstEnergy’s regulated utilities to recover regulatory assets or increasedcollect transition and other costs.
Operation and maintenance costs being higher than anticipated.
Other legislative and regulatory changes, and revised environmental requirements, including possible GHG emission, water intake and coal combustion residual regulations.
Theregulations, the potential impacts of the proposed rules promulgated by the EPA on July 6, 2010, in response to the U.S. Court of Appeals’ July 11, 2008 decision requiring revisions to the CAIR rules or any final laws, rules or regulations that may ultimately replace CAIR.CAIR, including the Cross-State Air Pollution Rule (CSAPR), and the effects of the EPA’s recently released MACT proposal to establish certain mercury and other emission standards for electric generating units.
The uncertainty of the timing and amounts of the capital expenditures needed to, among other things, implement the Air Quality Compliance Planthat may arise in connection with any NSR litigation or potential regulatory initiatives or rulemakings (including that such amountsexpenditures could be higher than anticipatedresult in our decision to shut down or thatidle certain generating units may need to be shut down) or levels of emission reductions related to the Consent Decree resolving the NSR litigation or other potential similar regulatory initiatives or actions.units).
Adverse regulatory or legal decisions and outcomes with respect to our nuclear operations (including, but not limited to the revocation or non-renewal of necessary licenses, approvals or operating permits and oversight) by the NRC.NRC including as a result of the incident at Japan’s Fukushima Daiichi Nuclear Plant).
Ultimate resolution ofAdverse legal decisions and outcomes related to Met-Ed’s and Penelec’s TSC filings with the PPUC.ability to recover certain transmission costs through their transmission service charge riders.
The continuing availability of generating units and changes in their ability to operate at or near full capacity.
Replacement power costs being higher than anticipated or inadequately hedged.
The ability to comply with applicable state and federal reliability standards and energy efficiency mandates.
Changes in customers’ demand for power, including but not limited to, changes resulting from the implementation of state and federal energy efficiency mandates.
The ability to accomplish or realize anticipated benefits from strategic goals (including employee workforce initiatives).goals.
TheEfforts and our ability to improve electric commodity margins and the impact of, among other factors, the increased cost of coal and coal transportation on such margins.
The ability to experience growth in the distribution business.
The changing market conditions that could affect the value of assets held in the registrants’FirstEnergy’s nuclear decommissioning trusts, pension trusts and other trust funds, and cause FirstEnergyus to make additional contributions sooner, or in amounts that are larger than currently anticipated.
The ability to access the public securities and other capital and credit markets in accordance with FirstEnergy’s financing plan, and the cost of such capital.capital and overall condition of the capital and credit markets affecting FirstEnergy and its subsidiaries.
Changes in general economic conditions affecting the registrants.
The state of the capitalFirstEnergy and credit markets affecting the registrants.its subsidiaries.
Interest rates and any actions taken by credit rating agencies that could negatively affect the registrants’FirstEnergy’s and its subsidiaries’ access to financing or their costs and increase requirements to post additional collateral to support outstanding commodity positions, LOCs and other financial guarantees.
The statecontinuing uncertainty of the national and regional economieseconomy and associated impactsits impact on the registrants’FirstEnergy’s and its subsidiaries’ major industrial and commercial customers.
Issues concerning the soundness of financial institutions and counterparties with which the registrantsFirstEnergy and its subsidiaries do business.
The expected timingIssues arising from the recently completed merger of FirstEnergy and likelihood of completion of the proposed merger with Allegheny Energy, Inc., and the ongoing coordination of their combined operations including the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the proposed merger that could reduce anticipated benefits or cause the parties to abandon the merger, the diversion of management’s time and attention from FirstEnergy’s ongoing business during this time period, the ability to maintain relationships with customers, employees or suppliers, as well as the ability to successfully integrate the businesses and realize cost savings and any other synergies and the risk that the credit ratings of the combined company or its subsidiaries may be different from what the companies expect.
The risks and other factors discussed from time to time in the registrants’ SEC filings, and other similar factors.
Dividends declared from time to time on FirstEnergy’s common stock during any annual period may in aggregate vary from the indicated amount due to circumstances considered by FirstEnergy’s Board of Directors at the time of the actual declarations. A security rating is not a recommendation to buy, or hold securities and is subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.
The foregoing review of factors should not be construed as exhaustive. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor assess the impact of any such factor on the registrants’ business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. A security rating is not a recommendation to buy, sell or hold securities that may be subject to revision or withdrawal at any time by the assigning rating organization. Each rating should be evaluated independently of any other rating. The registrants expressly disclaim any current intention to update any forward-looking statements contained herein as a result of new information, future events or otherwise.

 

 

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

 

i

TABLE OF CONTENTS (Cont’d)
     
  Page 
     
Combined Notes To Consolidated Financial Statements
  2627 
     
Item 2. Management’s Discussion and Analysis of Registrant and Subsidiaries
  6384 
     
Management’s Narrative Analysis of Results of Operations
    
     
FirstEnergy Solutions Corp.
  99131 
     
Ohio Edison Company
  102134 
     
The Cleveland Electric Illuminating Company
  104136 
     
The Toledo Edison Company
  106138 
     
Jersey Central Power & Light Company
  108140 
     
Metropolitan Edison Company
  110142 
     
Pennsylvania Electric Company
  112144 
     
Item 3. Quantitative and Qualitative Disclosures About Market Risk
  114146 
     
Item 4. Controls and Procedures — FirstEnergy
  114
Item 4T. Controls and Procedures — FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec
114146 
     
Part II. Other Information
    
     
Item 1. Legal Proceedings
  114147 
     
Item 1A. Risk Factors
  114147 
     
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
  114147 
     
Item 5. Other Information
  114147 
     
Item 6. Exhibits
  115148 
     
 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:
   
AEAllegheny Energy, Inc., a Maryland utility holding company that merged with a subsidiary of FirstEnergy on February 25, 2011
AESCAllegheny Energy Service Corporation, a subsidiary of AE
AE SupplyAllegheny Energy Supply Company LLC, an unregulated generation subsidiary of AE
AETAllegheny Energy Transmission, LLC, a parent of TrAIL and PATH
AGCAllegheny Generating Company, a generation subsidiary of AE
AlleghenyAllegheny Energy, Inc., together with its consolidated subsidiaries
AVEAllegheny Ventures, Inc.
ATSI American Transmission Systems, Incorporated, which owns and operates transmission facilities
CEI The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
FENOC FirstEnergy Nuclear Operating Company, which operates nuclear generating facilities
FES FirstEnergy Solutions Corp., which provides energy-related products and services
FESC FirstEnergy Service Company, which provides legal, financial and other corporate support services
FEV FirstEnergy Ventures Corp., which invests in certain unregulated enterprises and business ventures
FGCO FirstEnergy Generation Corp., which owns and operates non-nuclear generating facilities
FirstEnergy FirstEnergy Corp., a public utility holding company
Global Rail A joint venture between FirstEnergy Ventures Corp.FEV and WMB Loan Ventures II LLC, that owns coal transportation operations near Roundup, Montana
GPU GPU, Inc., former parent of JCP&L, Met-Ed and Penelec, whichthat merged with FirstEnergy on November 7, 2001
JCP&L Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
Met-Ed Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
MPMonongahela Power Company, a West Virginia electric utility operating subsidiary of AE
NGC FirstEnergy Nuclear Generation Corp., owns nuclear generating facilities
OE Ohio Edison Company, an Ohio electric utility operating subsidiary
Ohio Companies CEI, OE and TE
PATHPotomac-Appalachian Transmission Highline LLC, a joint venture between Allegheny and a subsidiary of American Electric Power Company, Inc.
PATH-VAPATH Allegheny Virginia Transmission Corporation
PEThe Potomac Edison Company, a Maryland electric operating subsidiary of AE
Penelec Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
Penn Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
Pennsylvania Companies Met-Ed, Penelec, Penn and PennWP
PNBV PNBV Capital Trust, a special purpose entity created by OE in 1996
Shippingport Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
Signal Peak A joint venture between FirstEnergy Ventures Corp.FEV and WMB Loan Ventures LLC, that owns mining operations near Roundup, Montana
TE The Toledo Edison Company, an Ohio electric utility operating subsidiary
TrAILTrans-Allegheny Interstate Line Company
Utilities OE, CEI, TE, Penn, JCP&L, Met-Ed, Penelec, MP, PE and WP
Utility RegistrantsOE, CEI, TE, JCP&L, Met-Ed and Penelec
The following abbreviations and acronyms are used to identify frequently used terms in this report:
WPWest Penn Power Company, a Pennsylvania electric utility operating subsidiary of AE
 
The following abbreviations and acronyms are used to identify frequently used terms in this report:
 
ALJ Administrative Law Judge
AOCL Accumulated Other Comprehensive Loss
AEPAmerican Electric Power
AQC Air Quality Control
ARO Asset Retirement Obligation
ARRAuction Revenue Rights
BGS Basic Generation Service
BMPBruce Mansfield Plant
CAA Clean Air Act
CAIR Clean Air Interstate Rule
CAMR Clean Air Mercury Rule
CATR Clean Air Transport Rule
CBP Competitive Bid Process

iii

GLOSSARY OF TERMS, Cont’d.
CCBCoal Combustion By-products
CDWRCalifornia Department of Water Resources
CO2
 Carbon Dioxide
CSAPRCross-State Air Pollution Rule
CTC Competitive Transition Charge
CWAClean Water Act
CWIPConstruction Work in Progress
DCPDDeferred Compensation Plan for Outside Directors
DOE United States Department of Energy
DOJ United States Department of Justice
DPA Department of the Public Advocate, Division of Rate Counsel (New Jersey)
DSPDefault Service Plan
EDCPExecutive Deferred Compensation Plan
EE&C Energy Efficiency and Conservation
EISEnergy Insurance Services, Inc.
EMP Energy Master Plan
ENECExpanded Net Energy Cost
EPA United States Environmental Protection Agency

iii

GLOSSARY OF TERMS, Cont’d.
ESOP Employee Stock Ownership Plan
ESP Electric Security Plan
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
FMB First Mortgage Bond
FPA Federal Power Act
FRR Fixed Resource Requirement
FTRsFinancial Transmission Rights
GAAP Generally Accepted Accounting Principles in the United States
RGGIRegional Greenhouse Gas Initiative
GHG Greenhouse Gases
IRS Internal Revenue Service
JOA Joint Operating Agreement
kV Kilovolt
KWH Kilowatt-hours
LBRLittle Blue Run
LED Light-Emitting Diode
LOC Letter of Credit
LSELoad Serving Entity
LTIPLong-Term Incentive Plan
MACT Maximum Achievable Control Technology
MDEMaryland Department of the Environment
MDPSC Maryland Public Service Commission
MEIUG Met-Ed Industrial usersUsers Group
MISO Midwest Independent Transmission System Operator, Inc.
Moody’s Moody’s Investors Service, Inc.
MRO Market Rate Offer
MSHAMine Safety and Health Administration
MTEP MISO Regional Transmission Expansion Plan
MVPMulti-value Project
MW Megawatts
MWH Megawatt-hours
NAAQS National Ambient Air Quality Standards
NDTNuclear Decommissioning Trusts
NERC North American Electric Reliability Corporation
NJBPU New Jersey Board of Public Utilities
NNSR Non-Attainment New Source Review
NOAC Northwest Ohio Aggregation Coalition
NOPEC Northeast Ohio Public Energy Council
NOV Notice of Violation
NOX
 Nitrogen Oxide
NPDESNational Pollutant Discharge Elimination System
NRC Nuclear Regulatory Commission

iv

GLOSSARY OF TERMS, Cont’d.
NSR New Source Review
NUG Non-Utility Generation
NUGC Non-Utility Generation Charge
NYSEG New York State Electric and Gas
OCC Ohio Consumers’ Counsel
OCI Other Comprehensive Income
OPEB Other Post-Employment Benefits
OSBAOffice of Small Business Advocate
OVEC Ohio Valley Electric Corporation
PA DEPPennsylvania Department of Environmental Protection
PCRB Pollution Control Revenue Bond
PICA Pennsylvania Intergovernmental Cooperation Authority
PJM PJM Interconnection L. L. C.
POLR Provider of Last Resort; an electric utility’s obligation to provide generation service to customers whose alternative supplier fails to deliver service
PPUC Pennsylvania Public Utility Commission
PSCWV Public Service Commission of West Virginia
PSA Power Supply Agreement
PSD Prevention of Significant Deterioration
PUCO Public Utilities Commission of Ohio
PURPAPublic Utility Regulatory Policies Act of 1978
RECs Renewable Energy Credits
RFP Request for Proposal
RGGIRegional Greenhouse Gas Initiative
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
SMIPSmart Meter Implementation Plan
SNCR Selective Non-Catalytic Reduction
SO2
 Sulfur Dioxide
SOSStandard Offer Service
TBC Transition Bond Charge
TDSTotal Dissolved Solid
TMDLTotal Maximum Daily Load
TMI-2 Three Mile Island Unit 2
TSC Transmission Service Charge
VIE Variable Interest Entity
VSCC Virginia State Corporation Commission
WVDEPWest Virginia Department of Environmental Protection
WVPSCPublic Service Commission of West Virginia

 

v

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
                         
 Three Months Nine Months  Three Months Six Months 
 Ended September 30 Ended September 30  Ended June 30 Ended June 30 
 2010 2009 2010 2009 
 (In millions, except per share amounts) 
In millions, except per share amounts 2011 2010 2011 2010 
REVENUES:
  
Electric utilities $2,757 $2,940 $7,673 $8,751  $2,590 $2,373 $4,925 $4,916 
Unregulated businesses 936 468 2,449 1,262  1,470 766 2,711 1,522 
                  
Total revenues* 3,693 3,408 10,122 10,013  4,060 3,139 7,636 6,438 
                  
  
EXPENSES:
  
Fuel 400 302 1,084 890  635 350 1,088 684 
Purchased power 1,284 1,313 3,574 3,480  1,220 1,063 2,406 2,301 
Other operating expenses 738 665 2,112 2,103  1,105 673 2,138 1,374 
Provision for depreciation 182 188 565 550  282 190 502 383 
Amortization of regulatory assets 176 261 549 903  90 161 222 373 
Deferral of new regulatory assets — — —  (136)
General taxes 206 192 587 587  242 176 479 381 
Impairment of long-lived assets 292 — 294 — 
                  
Total expenses 3,278 2,921 8,765 8,377  3,574 2,613 6,835 5,496 
                  
  
OPERATING INCOME
 415 487 1,357 1,636  486 526 801 942 
                  
  
OTHER INCOME (EXPENSE):
  
Investment income 46 191 93 207  31 31 52 47 
Interest expense  (208)  (355)  (628)  (755)  (265)  (207)  (496)  (420)
Capitalized interest 41 35 122 96  20 40 38 81 
                  
Total other expense  (121)  (129)  (413)  (452)  (214)  (136)  (406)  (292)
                  
  
INCOME BEFORE INCOME TAXES
 294 358 944 1,184  272 390 395 650 
  
INCOME TAXES
 119 128 364 430  101 134 179 245 
                  
  
NET INCOME
 175 230 580 754  171 256 216 405 
  
Loss attributable to noncontrolling interest  (4)  (4)  (19)  (14)  (10)  (9)  (15)  (15)
                  
  
EARNINGS AVAILABLE TO FIRSTENERGY CORP.
 $179 $234 $599 $768  $181 $265 $231 $420 
                  
  
BASIC EARNINGS PER SHARE OF COMMON STOCK
 $0.59 $0.77 $1.97 $2.52 
         
 
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING
 304 304 304 304 
         
 
DILUTED EARNINGS PER SHARE OF COMMON STOCK
 $0.59 $0.77 $1.96 $2.51 
         
 
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING
 305 306 305 306 
         
 
EARNINGS PER SHARE OF COMMON STOCK:
 
Basic $0.43 $0.87 $0.61 $1.38 
Diluted $0.43 $0.87 $0.61 $1.37 
AVERAGE SHARES OUTSTANDING:
 
Basic 418 304 380 304 
Diluted 420 305 382 305 
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK
 $1.10 $1.10 $1.65 $1.65  — — $0.55 $0.55 
         
   
* Includes excise tax collections of $120$116 million and $106$99 million in the three months ended SeptemberJune 30, 20102011 and 2009,2010, respectively, and $328$235 million and $310$208 million in the ninesix months ended SeptemberJune 30, 20102011 and 2009,2010, respectively.
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

1

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
                 
  Three Months  Nine Months 
  Ended September 30  Ended September 30 
  2010  2009  2010  2009 
  (In millions) 
                 
NET INCOME
 $175  $230  $580  $754 
             
                 
OTHER COMPREHENSIVE INCOME (LOSS):
                
Pension and other postretirement benefits  17   (480)  47   24 
Unrealized gain on derivative hedges  6   19   16   57 
Change in unrealized gain on available-for-sale securities  20   (108)  32   (76)
             
Other comprehensive income (loss)  43   (569)  95   5 
Income tax expense (benefit) related to other comprehensive income  14   (216)  30   26 
             
Other comprehensive income (loss), net of tax  29   (353)  65   (21)
             
                 
COMPREHENSIVE INCOME (LOSS)
  204   (123)  645   733 
                 
COMPREHENSIVE LOSS ATTRIBUTABLE TO NONCONTROLLING INTEREST
  (4)  (4)  (19)  (14)
             
                 
COMPREHENSIVE INCOME (LOSS) AVAILABLE TO FIRSTENERGY CORP.
 $208  $(119) $664  $747 
             
                 
  Three Months  Six Months 
  Ended June 30  Ended June 30 
(In millions) 2011  2010  2011  2010 
                 
NET INCOME
 $171  $256  $216  $405 
             
                 
OTHER COMPREHENSIVE INCOME:
                
Pension and other postretirement benefits  111   17   130   30 
Unrealized gain on derivative hedges  17   6   11   10 
Change in unrealized gain on available-for-sale securities  10   6   19   12 
             
Other comprehensive income  138   29   160   52 
Income tax expense related to other comprehensive income  53   9   54   16 
             
Other comprehensive income, net of tax  85   20   106   36 
             
                 
COMPREHENSIVE INCOME
  256   276   322   441 
                 
COMPREHENSIVE LOSS ATTRIBUTABLE
                
TO NONCONTROLLING INTEREST
  (10)  (9)  (15)  (15)
             
                 
COMPREHENSIVE INCOME AVAILABLE TO FIRSTENERGY CORP.
 $266  $285  $337  $456 
             
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

2

FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                
 September 30, December 31,  June 30, December 31, 
 2010 2009 
 (In millions) 
(In millions) 2011 2010 
ASSETS
  
  
CURRENT ASSETS:
  
Cash and cash equivalents $632 $874  $476 $1,019 
Receivables-  
Customers (less allowances of $39 million in 2010 and $33 million in 2009) 1,414 1,244 
Other (less allowances of $7 million in 2010 and 2009) 150 153 
Customers, net of allowance for uncollectible accounts of $35 in 2011 and $36 in 2010 1,578 1,392 
Other, net of allowance for uncollectible accounts of $8 in 2011 and 2010 256 176 
Materials and supplies, at average cost 652 647  866 638 
Prepaid taxes 291 248  474 199 
Derivatives 265 182 
Other 252 154  203 92 
          
 3,391 3,320  4,118 3,698 
          
PROPERTY, PLANT AND EQUIPMENT:
  
In service 27,590 27,826  39,568 29,451 
Less — Accumulated provision for depreciation 11,206 11,397  11,593 11,180 
          
 16,384 16,429  27,975 18,271 
Construction work in progress 3,154 2,735  1,465 1,517 
Property, plant and equipment held for sale, net 502 — 
          
 19,538 19,164  29,942 19,788 
          
INVESTMENTS:
  
Nuclear plant decommissioning trusts 1,965 1,859  2,051 1,973 
Investments in lease obligation bonds 486 543  414 476 
Nuclear fuel disposal trust 212 208 
Other 564 621  479 345 
          
 3,015 3,023  3,156 3,002 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Goodwill 5,575 5,575  6,456 5,575 
Regulatory assets 2,246 2,356  2,182 1,826 
Power purchase contract asset 116 200 
Intangible assets 973 256 
Other 826 666  769 660 
          
 8,763 8,797  10,380 8,317 
          
 $34,707 $34,304  $47,596 $34,805 
          
LIABILITIES AND CAPITALIZATION
  
  
CURRENT LIABILITIES:
  
Currently payable long-term debt $1,590 $1,834  $2,058 $1,486 
Short-term borrowings 1,000 1,181  656 700 
Accounts payable 813 829  1,122 872 
Accrued taxes 230 314  399 326 
Accrued compensation and benefits 331 315 
Derivatives 287 266 
Other 1,339 1,130  691 733 
          
 4,972 5,288  5,544 4,698 
          
CAPITALIZATION:
  
Common stockholders’ equity-  
Common stock, $0.10 par value, authorized 375,000,000 shares- 304,835,407 shares outstanding 31 31 
Common stock, $0.10 par value, authorized 490,000,000 and 375,000,000 shares, respectively- 418,216,437 and 304,835,407 shares outstanding, respectively 42 31 
Other paid-in capital 5,445 5,448  9,782 5,444 
Accumulated other comprehensive loss  (1,350)  (1,415)  (1,433)  (1,539)
Retained earnings 4,591 4,495  4,607 4,609 
          
Total common stockholders’ equity 8,717 8,559  12,998 8,545 
Noncontrolling interest  (26)  (2)  (48)  (32)
          
Total equity 8,691 8,557  12,950 8,513 
Long-term debt and other long-term obligations 12,104 11,908  16,491 12,579 
          
 20,795 20,465  29,441 21,092 
          
NONCURRENT LIABILITIES:
  
Accumulated deferred income taxes 2,824 2,468  5,219 2,879 
Retirement benefits 1,541 1,534  2,134 1,868 
Asset retirement obligations 1,394 1,425  1,459 1,407 
Deferred gain on sale and leaseback transaction 968 993  942 959 
Power purchase contract liability 756 643 
Lease market valuation liability 228 262 
Adverse power contract liability 649 466 
Other 1,229 1,226  2,208 1,436 
          
 8,940 8,551  12,611 9,015 
          
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
  
 $34,707 $34,304  $47,596 $34,805 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

3

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
                
 Nine Months Ended  Six Months Ended 
 September 30  June 30 
 2010 2009 
 (In millions) 
(In millions) 2011 2010 
  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income $580 $754  $216 $405 
Adjustments to reconcile net income to net cash from operating activities-  
Provision for depreciation 565 550  502 383 
Amortization of regulatory assets 549 903  222 373 
Deferral of new regulatory assets —  (136)
Nuclear fuel and lease amortization 123 92  92 76 
Deferred purchased power and other costs  (192)  (235)  (168)  (146)
Deferred income taxes and investment tax credits, net 259 421  552 159 
Impairment of long-lived assets 294 — 
Investment impairment 21 39 
Gain on investment securities held in trusts  (39)  (172)
Loss on debt redemption — 142 
Deferred rents and lease market valuation liability  (21)  (20)  (61)  (62)
Accrued compensation and retirement benefits 48 20  49  (27)
Commodity derivative transactions, net  (21)  (29)
Pension trust contribution  (262) — 
Asset impairments 41 21 
Cash collateral paid, net  (31)  (63)
Interest rate swap transactions 129 —  — 43 
Commodity derivative transactions, net  (40) 26 
Cash collateral paid, net  (54)  (85)
Pension trust contribution —  (500)
Decrease (increase) in operating assets-  
Receivables  (172) 78  199  (156)
Materials and supplies  (6) 30  24  (17)
Prepayments and other current assets  (4)  (349)  (268)  (81)
Increase (decrease) in operating liabilities-  
Accounts payable  (16)  (103)  (28) 18 
Accrued taxes  (18)  (97)  (66)  (58)
Accrued interest 63 121   (4) 10 
Other 4  (15) 43 9 
          
Net cash provided from operating activities 2,073 1,464  1,031 858 
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New Financing-  
Long-term debt 251 4,151  503 — 
Short-term borrowings, net — 281 
Redemptions and Repayments-  
Long-term debt  (422)  (2,213)  (1,002)  (407)
Short-term borrowings, net  (171)  (764)  (44) — 
Common stock dividend payments  (503)  (503)  (420)  (335)
Other  (25)  (54)  (76)  (23)
          
Net cash provided from (used for) financing activities  (870) 617 
Net cash used for financing activities  (1,039)  (484)
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (1,467)  (1,575)  (1,018)  (997)
Proceeds from asset sales 117 19  — 116 
Sales of investment securities held in trusts 2,577 3,039  1,703 1,915 
Purchases of investment securities held in trusts  (2,610)  (3,101)  (1,807)  (1,934)
Customer acquisition costs  (110) —   (2)  (105)
Cash investments 56  (4) 50 59 
Restricted funds for debt redemption —  (150)
Cash received in Allegheny merger 590 — 
Other  (8)  (16)  (51)  (21)
          
Net cash used for investing activities  (1,445)  (1,788)  (535)  (967)
          
  
Net change in cash and cash equivalents  (242) 293   (543)  (593)
Cash and cash equivalents at beginning of period 874 545  1,019 874 
          
Cash and cash equivalents at end of period $632 $838  $476 $281 
          
 
SUPPLEMENTAL CASH FLOW INFORMATION:
 
Non-cash transaction: merger with Allegheny, common stock issued $4,354 $— 
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

4

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                         
 Three Months Ended Nine Months Ended  Three Months Ended Six Months Ended 
 September 30 September 30  June 30 June 30 
 2010 2009 2010 2009 
(In millions) 2011 2010 2011 2010 
STATEMENTS OF INCOME
 
 (In thousands)  
REVENUES:
  
Electric sales to non-affiliates $1,052 $729 $2,097 $1,397 
Electric sales to affiliates $599,695 $616,300 $1,745,542 $2,348,741  170 539 431 1,146 
Electric sales to non-affiliates 904,752 443,819 2,302,240 928,944 
Other 49,230 44,453 208,662 394,145  70 58 156 171 
                  
Total revenues 1,553,677 1,104,572 4,256,444 3,671,830  1,292 1,326 2,684 2,714 
                  
  
EXPENSES:
  
Fuel 391,087 294,693 1,061,719 871,160  316 343 659 671 
Purchased power from affiliates 116,381 35,290 246,232 149,746  65 69 134 130 
Purchased power from non-affiliates 411,084 205,200 1,160,119 551,155  329 310 626 760 
Other operating expenses 309,793 305,935 916,366 891,555  429 304 910 608 
Provision for depreciation 59,298 66,041 185,535 192,962  68 63 136 126 
General taxes 21,804 21,700 70,822 66,361  30 22 60 49 
Impairment of long-lived assets 291,934 — 293,767 —  7 — 20 2 
                  
Total expenses 1,601,381 928,859 3,934,560 2,722,939  1,244 1,111 2,545 2,346 
                  
  
OPERATING INCOME (LOSS)
  (47,704) 175,713 321,884 948,891 
OPERATING INCOME
 48 215 139 368 
                  
  
OTHER INCOME (EXPENSE):
  
Investment income 29,895 158,857 43,978 135,723  16 13 22 14 
Miscellaneous income 4,765 2,804 10,468 12,840 
Miscellaneous income (expense)  4  4 8 7 
Interest expense — affiliates  (2,497)  (2,209)  (7,362)  (8,503)  (2)  (2)  (3)  (5)
Interest expense — other  (49,544)  (42,187)  (150,560)  (90,985)  (52)  (51)  (105)  (101)
Capitalized interest 22,955 17,869 66,550 41,975  10 24 20 44 
                  
Total other income (expense) 5,574 135,134  (36,926) 91,050 
Total other expense  (24)  (12)  (58)  (41)
                  
  
INCOME (LOSS) BEFORE INCOME TAXES
  (42,130) 310,847 284,958 1,039,941 
INCOME BEFORE INCOME TAXES
 24 203 81 327 
  
INCOME TAXES
  (5,404) 111,164 107,833 372,175  4 69 25 113 
                  
  
NET INCOME (LOSS)
  (36,726) 199,683 177,125 667,766 
NET INCOME
 $20 $134 $56 $214 
                  
  
OTHER COMPREHENSIVE INCOME (LOSS):
 
STATEMENTS OF COMPREHENSIVE INCOME
 
 
NET INCOME
 $20 $134 $56 $214 
         
 
OTHER COMPREHENSIVE INCOME:
 
Pension and other postretirement benefits 886  (61,085)  (8,063) 13,604  1 1 3  (9)
Unrealized gain on derivative hedges 2,818 790 7,109 26,847  14 3 5 4 
Change in unrealized gain on available-for-sale securities 17,445  (89,401) 28,533  (51,374) 8 6 15 11 
                  
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 23 10 23 6 
Income taxes related to other comprehensive income 10 4 8 2 
                  
Other comprehensive income (loss), net of tax 13,455  (90,813) 17,681  (7,374)
Other comprehensive income, net of tax 13 6 15 4 
                  
  
TOTAL COMPREHENSIVE INCOME (LOSS)
 $(23,271) $108,870 $194,806 $660,392 
COMPREHENSIVE INCOME
 $33 $140 $71 $218 
                  
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

5

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED BALANCE SHEETS
(Unaudited)
                
 September 30, December 31,  June 30, December 31, 
 2010 2009 
 (In thousands) 
(In millions) 2011 2010 
ASSETS
  
 
CURRENT ASSETS:
  
Cash and cash equivalents $10 $12  $6 $9 
Receivables-  
Customers (less accumulated provisions of $16,277,000 and $12,041,000, respectively, for uncollectible accounts) 325,265 195,107 
Customers, net of allowance for uncollectible accounts of $18 in 2011 and $17 in 2010 450 366 
Associated companies 269,986 318,561  490 478 
Other (less accumulated provisions of $6,702,000 for uncollectible accounts) 57,407 51,872 
Other, net of allowances for uncollectible accounts of $3 in 2011 and $7 in 2010 51 90 
Notes receivable from associated companies 501,648 805,103  490 397 
Materials and supplies, at average cost 554,043 539,541  499 545 
Derivatives 221 182 
Prepayments and other 204,065 107,782  49 59 
          
 1,912,424 2,017,978  2,256 2,126 
          
PROPERTY, PLANT AND EQUIPMENT:
  
In service 9,663,264 10,357,632  11,455 11,321 
Less — Accumulated provision for depreciation 4,114,381 4,531,158  4,206 4,024 
          
 5,548,883 5,826,474  7,249 7,297 
Construction work in progress 2,736,635 2,423,446  694 1,063 
Property, plant and equipment held for sale, net 487 — 
          
 8,285,518 8,249,920  8,430 8,360 
          
INVESTMENTS:
  
Nuclear plant decommissioning trusts 1,158,376 1,088,641  1,184 1,146 
Other 7,400 22,466  10 12 
          
 1,165,776 1,111,107  1,194 1,158 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Accumulated deferred income tax benefits 3,357 86,626 
Customer intangibles 127,420 16,566  129 134 
Goodwill 24,248 24,248  24 24 
Property taxes 50,125 50,125  41 41 
Unamortized sale and leaseback costs 61,934 72,553  76 73 
Derivatives 135 98 
Other 164,332 121,665  75 48 
          
 431,416 371,783  480 418 
          
 $11,795,134 $11,750,788  $12,360 $12,062 
          
LIABILITIES AND CAPITALIZATION
  
 
CURRENT LIABILITIES:
  
Currently payable long-term debt $1,396,792 $1,550,927  $1,088 $1,132 
Short-term borrowings-  
Associated companies 9,642 9,237  541 12 
Other 100,000 100,000  1 — 
Accounts payable-  
Associated companies 472,018 466,078  393 467 
Other 204,928 245,363  191 241 
Accrued taxes 59,422 83,158 
Derivatives 242 266 
Other 430,824 359,057  262 322 
          
 2,673,626 2,813,820  2,718 2,440 
          
CAPITALIZATION:
  
Common stockholders’ equity- 
Common stock, without par value, authorized 750 shares, 7 shares outstanding 1,490,010 1,468,423 
Common stockholder’s equity- 
Common stock, without par value, authorized 750 shares- 7 shares outstanding 1,488 1,490 
Accumulated other comprehensive loss  (85,320)  (103,001)  (105)  (120)
Retained earnings 2,326,274 2,149,149  2,474 2,418 
          
Total common stockholders’ equity 3,730,964 3,514,571 
Total common stockholder’s equity 3,857 3,788 
Long-term debt and other long-term obligations 2,819,150 2,711,652  3,000 3,181 
          
 6,550,114 6,226,223  6,857 6,969 
          
NONCURRENT LIABILITIES:
  
Deferred gain on sale and leaseback transaction 967,583 992,869  942 959 
Accumulated deferred investment tax credits 55,267 58,396 
Accumulated deferred income taxes 216 58 
Asset retirement obligations 877,522 921,448  875 892 
Retirement benefits 228,779 204,035  295 285 
Property taxes 50,125 50,125 
Lease market valuation liability 228,119 262,200  194 217 
Derivatives 85 81 
Other 163,999 221,672  178 161 
          
 2,571,394 2,710,745  2,785 2,653 
          
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
  
 $11,795,134 $11,750,788  $12,360 $12,062 
          
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 
 (In thousands) 
(In millions) 2011 2010 
  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income $177,125 $667,766  $56 $214 
Adjustments to reconcile net income to net cash from operating activities-  
Provision for depreciation 185,535 192,962  136 126 
Nuclear fuel and lease amortization 126,071 94,244  92 78 
Deferred rents and lease market valuation liability  (41,493)  (40,143)  (58)  (59)
Deferred income taxes and investment tax credits, net 96,152 268,812  126 114 
Impairment of long-lived assets 293,767 — 
Investment impairment 21,089 36,169 
Asset impairments 28 21 
Accrued compensation and retirement benefits 15,887 5,860  8 7 
Commodity derivative transactions, net  (40,048) 25,794   (60)  (29)
Gain on asset sales  (2,213)  (9,832)
Gain on investment securities held in trusts  (34,292)  (154,723)
Cash collateral, net  (53,900)  (92,618)
Cash collateral paid, net  (40)  (38)
Decrease (increase) in operating assets-  
Receivables  (91,134)  (55,774)  (36)  (193)
Materials and supplies  (15,324) 38,543  50  (29)
Prepayments and other current assets 36,004  (35,315) 12 25 
Increase (decrease) in operating liabilities- 
Decrease in operating liabilities- 
Accounts payable  (50,114)  (72,181)  (124)  (32)
Accrued taxes  (8,404) 23,846   (29)  (8)
Accrued interest  (14,130) 31,770 
Other 23,349  (43,369) 21 21 
          
Net cash provided from operating activities 623,927 881,811  182 218 
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New Financing- 
New financing- 
Long-term debt 249,520 2,356,762  247 — 
Short-term borrowings, net 405 —  530 76 
Redemptions and Repayments- 
Redemptions and repayments- 
Long-term debt  (296,339)  (618,213)  (472)  (295)
Short-term borrowings, net —  (1,164,823)
Other  (798)  (20,006)  (11)  (1)
          
Net cash provided from (used for) financing activities  (47,212) 553,720  294  (220)
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (801,238)  (842,600)  (334)  (566)
Proceeds from asset sales 117,213 16,129  — 116 
Sales of investment securities held in trusts 1,478,086 2,152,717  513 957 
Purchases of investment securities held in trusts  (1,511,273)  (2,175,135)  (545)  (979)
Loans from (to) associated companies, net 303,455  (298,841)
Loans to associated companies, net  (93) 631 
Customer acquisition costs  (110,073) —   (2)  (105)
Leasehold improvement payments to associated companies  (51,204) —  —  (51)
Other  (1,683)  (20,882)  (18)  (1)
          
Net cash used for investing activities  (576,717)  (1,168,612)
Net cash provided from (used for) investing activities  (479) 2 
          
  
Net change in cash and cash equivalents  (2) 266,919   (3) — 
Cash and cash equivalents at beginning of period 12 39  9 — 
          
Cash and cash equivalents at end of period $10 $266,958  $6 $— 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

7

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                         
 Three Months Ended Nine Months Ended  Three Months Ended Six Months Ended 
 September 30 September 30  June 30 June 30 
 2010 2009 2010 2009 
(In thousands) 2011 2010 2011 2010 
 (In thousands)  
STATEMENTS OF INCOME
  
  
REVENUES:
  
Electric sales $456,531 $575,377 $1,351,893 $1,942,612  $360,203 $415,437 $724,034 $895,362 
Excise and gross receipts tax collections 30,058 27,127 82,482 81,055  24,941 23,949 53,136 52,424 
                  
Total revenues 486,589 602,504 1,434,375 2,023,667  385,144 439,386 777,170 947,786 
                  
  
EXPENSES:
  
Purchased power from affiliates 136,804 200,506 424,530 847,712  69,134 134,050 162,396 287,727 
Purchased power from non-affiliates 84,264 161,732 257,322 397,875  62,667 78,826 123,046 173,057 
Other operating expenses 94,804 102,463 271,934 372,231  110,778 88,275 212,240 177,130 
Provision for depreciation 21,990 22,407 65,884 65,916  22,470 22,014 44,346 43,894 
Amortization of regulatory assets, net 9,704 17,404 48,473 59,910  2,405 9,424 3,179 38,769 
General taxes 48,909 45,164 139,763 138,187  45,592 43,362 95,018 90,854 
                  
Total expenses 396,475 549,676 1,207,906 1,881,831  313,046 375,951 640,225 811,431 
                  
  
OPERATING INCOME
 90,114 52,828 226,469 141,836  72,098 63,435 136,945 136,355 
                  
  
OTHER INCOME (EXPENSE):
  
Investment income 5,438 20,285 16,991 39,796  5,043 6,309 9,351 11,553 
Miscellaneous income 1,673 237 2,676 2,108 
Miscellaneous income (expense)  (477) 1,295  (187) 1,003 
Interest expense  (21,975)  (22,961)  (66,440)  (67,717)  (22,011)  (22,155)  (44,156)  (44,465)
Capitalized interest 335 231 838 730  510 295 841 503 
                  
Total other expense  (14,529)  (2,208)  (45,935)  (25,083)  (16,935)  (14,256)  (34,151)  (31,406)
                  
  
INCOME BEFORE INCOME TAXES
 75,585 50,620 180,534 116,753  55,163 49,179 102,794 104,949 
  
INCOME TAXES
 29,332 15,885 60,797 36,742  16,538 11,856 34,029 31,465 
                  
  
NET INCOME
 46,253 34,735 119,737 80,011  38,625 37,323 68,765 73,484 
          
 
Income from noncontrolling interest 124 140 386 429 
Income attributable to noncontrolling interest 114 130 230 262 
                  
  
EARNINGS AVAILABLE TO PARENT
 $46,129 $34,595 $119,351 $79,582  $38,511 $37,193 $68,535 $73,222 
                  
  
STATEMENTS OF COMPREHENSIVE INCOME
  
  
NET INCOME
 $46,253 $34,735 $119,737 $80,011  $38,625 $37,323 $68,765 $73,484 
                  
  
OTHER COMPREHENSIVE INCOME LOSS:
 
OTHER COMPREHENSIVE INCOME:
 
Pension and other postretirement benefits 321  (49,043) 4,658 46,559  1,122 322 1,461 4,337 
Change in unrealized gain on available-for-sale securities 2,178  (7,695) 2,989  (9,676)
Increase in unrealized gain on available-for-sale securities 1,591 520 1,569 811 
                  
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 2,713 842 3,030 5,148 
Income tax expense (benefit) related to other 
comprehensive income 386  (26)  (1,110) 667 
                  
Other comprehensive income (loss), net of tax 1,937  (34,814) 6,418 20,968 
Other comprehensive income, net of tax 2,327 868 4,140 4,481 
                  
  
COMPREHENSIVE INCOME (LOSS)
 48,190  (79) 126,155 100,979 
COMPREHENSIVE INCOME
 40,952 38,191 72,905 77,965 
  
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST
 124 140 386 429 
COMPREHENSIVE INCOME ATTRIBUTABLE TO
 
NONCONTROLLING INTEREST
 114 130 230 262 
                  
  
COMPREHENSIVE INCOME (LOSS) AVAILABLE TO PARENT
 $48,066 $(219) $125,769 $100,550 
COMPREHENSIVE INCOME AVAILABLE TO PARENT
 $40,838 $38,061 $72,675 $77,703 
                  
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

8

OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                
 September 30, December 31,  June 30, December 31, 
 2010 2009 
(In thousands) 2011 2010 
 (In thousands)  
ASSETS
  
CURRENT ASSETS:
  
Cash and cash equivalents $288,092 $324,175  $176 $420,489 
Receivables-  
Customers (less accumulated provisions of $4,951,000 and $5,119,000, respectively, for uncollectible accounts) 182,894 209,384 
Customers, net of allowance for uncollectible accounts of $3,564 in 2011 and $4,086 in 2010 159,393 176,591 
Associated companies 38,499 98,874  68,709 118,135 
Other 20,777 14,155  32,798 12,232 
Notes receivable from associated companies 16,234 118,651  95,884 16,957 
Prepayments and other 9,490 15,964  35,339 6,393 
          
 555,986 781,203  392,299 750,797 
          
UTILITY PLANT:
  
In service 3,118,239 3,036,467  3,176,455 3,136,623 
Less — Accumulated provision for depreciation 1,199,401 1,165,394  1,230,570 1,207,745 
          
 1,918,838 1,871,073  1,945,885 1,928,878 
Construction work in progress 38,915 31,171  66,656 45,103 
          
 1,957,753 1,902,244  2,012,541 1,973,981 
          
OTHER PROPERTY AND INVESTMENTS:
  
Investment in lease obligation bonds 204,707 216,600  177,835 190,420 
Nuclear plant decommissioning trusts 129,685 120,812  133,354 127,017 
Other 96,897 96,861  92,440 95,563 
          
 431,289 434,273  403,629 413,000 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Regulatory assets 413,596 465,331  392,580 400,322 
Pension assets 39,271 19,881  62,612 28,596 
Property taxes 67,037 67,037  71,331 71,331 
Unamortized sale and leaseback costs 31,376 35,127  27,628 30,126 
Other 17,540 39,881  19,041 17,634 
          
 568,820 627,257  573,192 548,009 
          
 $3,513,848 $3,744,977  $3,381,661 $3,685,787 
          
LIABILITIES AND CAPITALIZATION
  
CURRENT LIABILITIES:
  
Currently payable long-term debt $1,479 $2,723  $1,429 $1,419 
Short-term borrowings-  
Associated companies 47,648 92,863  — 142,116 
Other 320 807  166 320 
Accounts payable-  
Associated companies 32,084 102,763  94,821 99,421 
Other 23,994 40,423  41,417 29,639 
Accrued taxes 55,236 81,868  69,364 78,707 
Accrued interest 25,354 25,749  25,374 25,382 
Other 133,060 81,424  79,795 74,947 
          
 319,175 428,620  312,366 451,951 
          
CAPITALIZATION:
  
Common stockholder’s equity-  
Common stock, without par value, authorized 175,000,000 shares - 60 shares outstanding 951,839 1,154,797 
Common stock, without par value, authorized 175,000,000 shares – 60 shares outstanding 783,871 951,866 
Accumulated other comprehensive loss  (157,159)  (163,577)  (174,936)  (179,076)
Retained earnings 104,241 29,890  110,156 141,621 
          
Total common stockholder’s equity 898,921 1,021,110  719,091 914,411 
Noncontrolling interest 6,225 6,442  5,313 5,680 
          
Total equity 905,146 1,027,552  724,404 920,091 
Long-term debt and other long-term obligations 1,152,370 1,160,208  1,151,720 1,152,134 
          
 2,057,516 2,187,760  1,876,124 2,072,225 
          
NONCURRENT LIABILITIES:
  
Accumulated deferred income taxes 678,815 660,114  749,687 696,410 
Accumulated deferred investment tax credits 10,521 11,406  9,439 10,159 
Retirement benefits 169,070 174,925  183,345 183,712 
Asset retirement obligations 83,194 85,926  69,164 74,456 
Other 195,557 196,226  181,536 196,874 
          
 1,137,157 1,128,597  1,193,171 1,161,611 
          
COMMITMENTS AND CONTINGENCIES (Note 9)
  
 $3,513,848 $3,744,977  $3,381,661 $3,685,787 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

9

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
                
 Nine Months Ended  Six Months Ended 
 September 30  June 30 
 2010 2009 
 (In thousands) 
(In thousands) 2011 2010 
  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income $119,737 $80,011  $68,765 $73,484 
Adjustments to reconcile net income to net cash from operating activities-  
Provision for depreciation 65,884 65,916  44,346 43,894 
Amortization of regulatory assets, net 48,473 59,910  3,179 38,769 
Purchased power cost recovery reconciliation 3,906 15,372   (8,584)  (1,514)
Amortization of lease costs 28,314 28,394   (4,696)  (4,619)
Deferred income taxes and investment tax credits, net 7,612 32,658  62,216 4,964 
Accrued compensation and retirement benefits  (16,659)  (3,542)  (8,328)  (16,154)
Accrued regulatory obligations 1,301 19,172   (3,309)  (2,309)
Electric service prepayment programs —  (4,634)
Cash collateral from suppliers 23,286 6,469 
Pension trust contributions —  (103,035)
Cash collateral from (to) suppliers, net  (850) 1,215 
Pension trust contribution  (27,000) — 
Decrease (increase) in operating assets-  
Receivables 91,971 128,688  80,968 49,250 
Prepayments and other current assets 10,331  (2,553)  (28,947) 5,072 
Decrease in operating liabilities-  
Accounts payable  (87,108)  (60,125)  (22,253)  (57,208)
Accrued taxes  (26,425)  (17,196)  (9,360)  (25,685)
Accrued interest  (395)  (59)
Other  (9,695)  (8,596) 4,261  (114)
          
Net cash provided from operating activities 260,533 236,850  150,408 109,045 
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New Financing- 
Long-term debt — 100,000 
Short-term borrowings, net — 74,514 
Redemptions and Repayments-  
Long-term debt  (9,628)  (101,088)  (707)  (2,957)
Short-term borrowings, net  (45,702) —   (142,270)  (93,017)
Common stock dividend payments  (250,000)  (150,000)  (268,000)  (250,000)
Other  (892)  (2,138)  (2,340)  (881)
          
Net cash used for financing activities  (306,222)  (78,712)  (413,317)  (346,855)
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (110,645)  (108,253)  (78,894)  (71,698)
Leasehold improvement payments from associated companies 18,375 —  — 18,375 
Sales of investment securities held in trusts 78,599 207,280  19,595 59,804 
Purchases of investment securities held in trusts  (83,725)  (214,592)  (25,547)  (64,063)
Loan repayments from associated companies, net 102,417 134,975 
Loans to associated companies, net  (78,927) 12,420 
Cash investments 12,296 7,070  11,962 11,774 
Other  (7,711)  (1,216)  (5,593)  (1,298)
          
Net cash provided from investing activities 9,606 25,264 
Net cash used for investing activities  (157,404)  (34,686)
          
  
Net change in cash and cash equivalents  (36,083) 183,402   (420,313)  (272,496)
Cash and cash equivalents at beginning of period 324,175 146,343  420,489 324,175 
          
Cash and cash equivalents at end of period $288,092 $329,745  $176 $51,679 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

10

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                         
 Three Months Ended Nine Months Ended  Three Months Ended Six Months Ended 
 September 30 September 30  June 30 June 30 
 2010 2009 2010 2009 
(In thousands) 2011 2010 2011 2010 
 (In thousands)  
STATEMENTS OF INCOME
  
 
REVENUES:
  
Electric sales $309,236 $417,900 $901,913 $1,307,592  $202,148 $280,180 $408,890 $592,677 
Excise tax collections 19,480 17,629 52,548 52,748  15,706 15,495 33,851 33,068 
                  
Total revenues 328,716 435,529 954,461 1,360,340  217,854 295,675 442,741 625,745 
                  
  
EXPENSES:
  
Purchased power from affiliates 89,389 153,556 298,204 635,927  36,040 99,422 82,208 208,815 
Purchased power from non-affiliates 35,151 87,689 105,200 208,849  23,099 32,651 41,319 70,049 
Other operating expenses 36,441 37,822 96,613 141,829  31,625 28,937 66,661 60,172 
Provision for depreciation 18,057 17,753 54,504 53,885  18,488 18,336 36,914 36,447 
Amortization of regulatory assets 45,136 39,313 121,082 325,630 
Deferral of new regulatory assets — — —  (134,587)
Amortization of regulatory assets, net 18,166 30,807 41,536 75,946 
General taxes 39,878 37,752 107,207 112,749  36,954 28,840 77,166 67,329 
                  
Total expenses 264,052 373,885 782,810 1,344,282  164,372 238,993 345,804 518,758 
                  
  
OPERATING INCOME
 64,664 61,644 171,651 16,058  53,482 56,682 96,937 106,987 
                  
  
OTHER INCOME (EXPENSE):
  
Investment income 6,604 7,565 20,756 23,599  5,637 6,605 12,234 14,152 
Miscellaneous income 533 645 1,790 3,437  1,038 675 1,674 1,257 
Interest expense  (33,384)  (34,740)  (100,267)  (100,819)  (32,135)  (33,262)  (65,213)  (66,883)
Capitalized interest 10 27 43 145  36 7 63 33 
                  
Total other expense  (26,237)  (26,503)  (77,678)  (73,638)  (25,424)  (25,975)  (51,242)  (51,441)
                  
  
INCOME (LOSS) BEFORE INCOME TAXES
 38,427 35,141 93,973  (57,580)
INCOME BEFORE INCOME TAXES
 28,058 30,707 45,695 55,546 
  
INCOME TAX EXPENSE (BENEFIT)
 13,479 9,755 33,107  (25,290)
INCOME TAXES
 6,209 8,785 10,645 19,628 
                  
  
NET INCOME (LOSS)
 24,948 25,386 60,866  (32,290)
NET INCOME
 21,849 21,922 35,050 35,918 
 
Income attributable to noncontrolling interest 309 366 675 785 
                  
  
Income from noncontrolling interest 366 418 1,151 1,295 
         
 
EARNINGS (LOSS) AVAILABLE TO PARENT
 $24,582 $24,968 $59,715 $(33,585)
EARNINGS AVAILABLE TO PARENT
 $21,540 $21,556 $34,375 $35,133 
                  
  
STATEMENTS OF COMPREHENSIVE INCOME
  
  
NET INCOME (LOSS)
 $24,948 $25,386 $60,866 $(32,290)
NET INCOME
 $21,849 $21,922 $35,050 $35,918 
                  
  
OTHER COMPREHENSIVE INCOME (LOSS):
  
Pension and other postretirement benefits 3,228  (48,024)  (16,129)  (154)
Unrealized loss on derivative hedges —  (1,451) —  (1,451)
         
Other comprehensive income (loss) 3,228  (49,475)  (16,129)  (1,605)
Pension and other postretirement benefits (charges) 2,975 3,228 5,942  (19,357)
Income tax expense (benefit) related to other comprehensive income 976  (17,854)  (6,325) 1,452  860 976 398  (7,301)
                  
Other comprehensive income (loss), net of tax 2,252  (31,621)  (9,804)  (3,057) 2,115 2,252 5,544  (12,056)
                  
  
COMPREHENSIVE INCOME (LOSS)
 27,200  (6,235) 51,062  (35,347)
COMPREHENSIVE INCOME
 23,964 24,174 40,594 23,862 
  
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST
 366 418 1,151 1,295  309 366 675 785 
                  
  
COMPREHENSIVE INCOME (LOSS) AVAILABLE TO PARENT
 $26,834 $(6,653) $49,911 $(36,642)
COMPREHENSIVE INCOME AVAILABLE TO PARENT
 $23,655 $23,808 $39,919 $23,077 
                  
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

11

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                
 September 30, December 31,  June 30, December 31, 
 2010 2009 
(In thousands) 2011 2010 
 (In thousands)  
ASSETS
  
 
CURRENT ASSETS:
  
Cash and cash equivalents $247 $86,230  $244 $238 
Receivables-  
Customers (less accumulated provisions of $5,271,000 and $5,239,000, respectively, for uncollectible accounts) 186,044 209,335 
Customers, net of allowance for uncollectible accounts of $2,801 in 2011 and $4,589 in 2010 97,997 183,744 
Associated companies 59,339 98,954  32,348 77,047 
Other 4,910 11,661  13,476 11,544 
Notes receivable from associated companies 23,905 26,802  71,911 23,236 
Materials and supplies, at average cost 13,784 398 
Prepayments and other 4,362 9,973  6,431 3,258 
          
 278,807 442,955  236,191 299,465 
          
UTILITY PLANT:
  
In service 2,373,419 2,310,074  2,417,031 2,396,893 
Less — Accumulated provision for depreciation 921,040 888,169  944,379 932,246 
          
 1,452,379 1,421,905  1,472,652 1,464,647 
Construction work in progress 30,482 36,907  59,281 38,610 
          
 1,482,861 1,458,812  1,531,933 1,503,257 
          
OTHER PROPERTY AND INVESTMENTS:
  
Investment in lessor notes 340,031 388,641  286,745 340,029 
Other 10,084 10,220  10,048 10,074 
          
 350,115 398,861  296,793 350,103 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Goodwill 1,688,521 1,688,521  1,688,521 1,688,521 
Regulatory assets 420,144 545,505  320,337 370,403 
Pension assets (Note 6) — 13,380 
Pension assets 14,652 — 
Property taxes 77,319 77,319  80,614 80,614 
Other 12,897 12,777  12,884 11,486 
          
 2,198,881 2,337,502  2,117,008 2,151,024 
          
 $4,310,664 $4,638,130  $4,181,925 $4,303,849 
          
LIABILITIES AND CAPITALIZATION
  
 
CURRENT LIABILITIES:
  
Currently payable long-term debt $148 $117  $188 $161 
Short-term borrowings- 
Associated companies 129,912 339,728 
Short-term borrowings from associated companies 23,303 105,996 
Accounts payable-  
Associated companies 14,803 68,634  51,001 32,020 
Other 13,725 17,166  18,700 14,947 
Accrued taxes 64,492 90,511  83,265 84,668 
Accrued interest 39,261 18,466  18,551 18,555 
Other 63,732 45,440  38,685 44,569 
          
 326,073 580,062  233,693 300,916 
          
CAPITALIZATION:
  
Common stockholders’ equity- 
Common stockholder’s equity- 
Common stock, without par value, authorized 105,000,000 shares, 67,930,743 shares outstanding 886,927 884,897  887,053 887,087 
Accumulated other comprehensive loss  (147,962)  (138,158)  (147,643)  (153,187)
Retained earnings 556,963 597,248  539,280 568,906 
          
Total common stockholders’ equity 1,295,928 1,343,987 
Total common stockholder’s equity 1,278,690 1,302,806 
Noncontrolling interest 17,651 20,592  15,195 18,017 
          
Total equity 1,313,579 1,364,579  1,293,885 1,320,823 
Long-term debt and other long-term obligations 1,852,511 1,872,750  1,831,023 1,852,530 
          
 3,166,090 3,237,329  3,124,908 3,173,353 
          
NONCURRENT LIABILITIES:
  
Accumulated deferred income taxes 628,244 644,745  640,059 622,771 
Accumulated deferred investment tax credits 11,205 11,836  10,574 10,994 
Retirement benefits 82,070 69,733  76,010 95,654 
Other 96,982 94,425  96,681 100,161 
          
 818,501 820,739  823,324 829,580 
          
COMMITMENTS AND CONTINGENCIES (Note 9)
  
 $4,310,664 $4,638,130  $4,181,925 $4,303,849 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

12

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)
                
 Nine Months Ended  Six Months Ended 
 September 30  June 30 
 2010 2009 
 (In thousands) 
(In thousands) 2011 2010 
  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income (Loss) $60,866 $(32,290)
Adjustments to reconcile net income (loss) to net cash from operating activities- 
Net Income $35,050 $35,918 
Adjustments to reconcile net income to net cash from operating activities- 
Provision for depreciation 54,504 53,885  36,914 36,447 
Amortization of regulatory assets, net 121,082 325,630  41,536 75,946 
Deferral of new regulatory assets —  (134,587)
Purchased power cost recovery reconciliation —  (3,478)
Deferred income taxes and investment tax credits, net  (24,283)  (41,939) 17,221  (18,083)
Accrued compensation and retirement benefits 10,467 10,311  5,421 5,421 
Accrued regulatory obligations  (2,001)  (444)
Cash collateral from suppliers, net — 685 
Pension trust contribution —  (89,789)  (35,000) — 
Electric service prepayment programs —  (3,510)
Cash collateral from suppliers, net 19,245 5,404 
Decrease (increase) in operating assets-  
Receivables 86,725 30,977  140,455 51,757 
Prepayments and other current assets 5,421  (633)  (17,469) 5,392 
Increase (decrease) in operating liabilities-  
Accounts payable  (57,272)  (32,240) 10,135  (34,488)
Accrued taxes  (23,876)  (17,003)  (346)  (11,317)
Accrued interest 20,795 29,816 
Other 740 11,489   (4,436) 2,023 
          
Net cash provided from operating activities 274,414 112,043  227,480 149,257 
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New Financing- 
Long-term debt — 298,398 
Redemptions and Repayments-  
Long-term debt  (84)  (558)  (74)  (54)
Short-term borrowings, net  (230,132)  (111,128)  (104,228)  (136,013)
Common stock dividend payments  (100,000)  (93,000)  (64,000)  (100,000)
Other  (4,100)  (6,161)  (5,239)  (3,367)
          
Net cash provided from (used for) financing activities  (334,316) 87,551 
Net cash used for financing activities  (173,541)  (239,434)
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (70,812)  (73,577)  (52,743)  (44,373)
Restricted cash —  (155,573)
Loan repayments from (to) associated companies, net 2,897  (4,638)
Loans to associated companies, net  (48,676) 2,322 
Redemptions of lessor notes 48,610 37,072  53,283 48,608 
Other  (6,776)  (2,871)  (5,797)  (2,365)
          
Net cash used for investing activities  (26,081)  (199,587)
Net cash provided from (used for) investing activities  (53,933) 4,192 
          
  
Net change in cash and cash equivalents  (85,983) 7  6  (85,985)
Cash and cash equivalents at beginning of period 86,230 226  238 86,230 
          
Cash and cash equivalents at end of period $247 $233  $244 $245 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

13

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                                
 Three Months Ended Nine Months Ended  Three Months Ended Six Months Ended 
 September 30 September 30  June 30 June 30 
 2010 2009 2010 2009 
(In thousands) 2011 2010 2011 2010 
 (In thousands)  
STATEMENTS OF INCOME
  
  
REVENUES:
  
Electric sales $136,058 $206,086 $376,180 $663,082  $93,048 $114,691 $199,373 $240,122 
Excise tax collections 7,979 7,422 21,079 21,448  6,270 6,059 13,572 13,100 
                  
Total revenues 144,037 213,508 397,259 684,530  99,318 120,750 212,945 253,222 
                  
  
EXPENSES:
  
Purchased power from affiliates 42,338 86,278 144,062 342,166  17,037 47,106 52,554 101,725 
Purchased power from non-affiliates 16,663 56,494 50,377 115,275  16,114 15,223 30,102 33,713 
Other operating expenses 28,746 30,238 79,790 110,722  32,549 25,499 69,136 51,044 
Provision for depreciation 7,800 7,847 23,763 23,136  7,959 8,013 15,890 15,963 
Amortization (deferral) of regulatory assets, net 6,591 9,253  (3,708) 30,921 
Deferral of regulatory assets, net  (7,054)  (1,800)  (18,532)  (10,299)
General taxes 14,023 13,205 39,766 39,804  12,438 12,282 26,890 25,743 
                  
Total expenses 116,161 203,315 334,050 662,024  79,043 106,323 176,040 217,889 
                  
  
OPERATING INCOME
 27,876 10,193 63,209 22,506  20,275 14,427 36,905 35,333 
                  
  
OTHER INCOME (EXPENSE):
  
Investment income 3,018 9,302 11,875 22,315  2,599 5,057 5,521 8,857 
Miscellaneous expense  (502)  (1,725)  (2,853)  (1,690)
Miscellaneous income (expense) 396  (945)  (1,233)  (2,351)
Interest expense  (10,479)  (10,854)  (31,421)  (25,649)  (10,415)  (10,455)  (20,858)  (20,942)
Capitalized interest 94 46 252 138  135 80 237 158 
                  
Total other expense  (7,869)  (3,231)  (22,147)  (4,886)  (7,285)  (6,263)  (16,333)  (14,278)
                  
  
INCOME BEFORE INCOME TAXES
 20,007 6,962 41,062 17,620  12,990 8,164 20,572 21,055 
  
INCOME TAX EXPENSE (BENEFIT)
 6,911  (138) 13,241 3,123 
INCOME TAXES
 1,429 948 3,164 6,330 
                  
  
NET INCOME
 13,096 7,100 27,821 14,497  11,561 7,216 17,408 14,725 
          
 
Income from noncontrolling interest  (4) 14 1 17 
Income attributable to noncontrolling interest 2 2 4 5 
                  
  
EARNINGS AVAILABLE TO PARENT
 $13,100 $7,086 $27,820 $14,480  $11,559 $7,214 $17,404 $14,720 
                  
  
STATEMENTS OF COMPREHENSIVE INCOME
  
  
NET INCOME
 $13,096 $7,100 $27,821 $14,497  $11,561 $7,216 $17,408 $14,725 
                  
  
OTHER COMPREHENSIVE INCOME (LOSS):
 
OTHER COMPREHENSIVE INCOME:
 
Pension and other postretirement benefits 713  (24,201) 1,723  (5,052) 575 714 1,167 1,010 
Change in unrealized gain on available-for-sale securities 427  (11,633) 466  (15,181)
Increase (decrease) in unrealized gain on available-for-sale securities 754  (330) 2,059 39 
                  
Other comprehensive income (loss) 1,140  (35,834) 2,189  (20,233)
Income tax expense (benefit) related to other comprehensive income 330  (13,187) 565  (5,982)
Other comprehensive income 1,329 384 3,226 1,049 
Income tax expense related to other comprehensive income 351 65 685 235 
                  
Other comprehensive income (loss), net of tax 810  (22,647) 1,624  (14,251)
Other comprehensive income, net of tax 978 319 2,541 814 
                  
  
COMPREHENSIVE INCOME (LOSS)
 13,906  (15,547) 29,445 246 
COMPREHENSIVE INCOME
 12,539 7,535 19,949 15,539 
  
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTEREST
  (4) 14 1 17 
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST
 2 2 4 5 
                  
  
COMPREHENSIVE INCOME (LOSS) AVAILABLE TO PARENT
 $13,910 $(15,561) $29,444 $229 
COMPREHENSIVE INCOME AVAILABLE TO PARENT
 $12,537 $7,533 $19,945 $15,534 
                  
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

14

THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                
 September 30, December 31,  June 30, December 31, 
 2010 2009 
(In thousands) 2011 2010 
 (In thousands)  
ASSETS
  
  
CURRENT ASSETS:
  
Cash and cash equivalents $134,158 $436,712  $12 $149,262 
Receivables-  
Customers 30 75 
Customers, net of allowance for uncollectible accounts of $1,142 in 2011 and $1 in 2010 45,931 29 
Associated companies 44,075 90,191  48,340 31,777 
Other (less accumulated provisions of $224,000 and $208,000, respectively, for uncollectible accounts) 19,146 20,180 
Other, net of allowance for uncollectible accounts of $339 in 2011 and $330 in 2010 5,272 18,464 
Notes receivable from associated companies 81,254 85,101  128,815 96,765 
Prepayments and other 4,272 7,111  12,052 2,306 
          
 282,935 639,370  240,422 298,603 
          
UTILITY PLANT:
  
In service 938,532 912,930  955,002 947,203 
Less — Accumulated provision for depreciation 440,510 427,376  453,517 446,401 
          
 498,022 485,554  501,485 500,802 
Construction work in progress 9,946 9,069  17,386 12,604 
          
 507,968 494,623  518,871 513,406 
          
OTHER PROPERTY AND INVESTMENTS:
  
Investment in lessor notes 103,848 124,357  82,153 103,872 
Nuclear plant decommissioning trusts 76,051 73,935  79,018 75,558 
Other 1,514 1,580  1,448 1,492 
          
 181,413 199,872  162,619 180,922 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Goodwill 500,576 500,576  500,576 500,576 
Regulatory assets 74,297 69,557  89,112 72,059 
Pension assets 24,603 — 
Property taxes 23,658 23,658  24,990 24,990 
Other 27,215 55,622  42,341 23,750 
          
 625,746 649,413  681,622 621,375 
          
 $1,598,062 $1,983,278  $1,603,534 $1,614,306 
          
LIABILITIES AND CAPITALIZATION
  
  
CURRENT LIABILITIES:
  
Currently payable long-term debt $208 $222  $188 $199 
Accounts payable-  
Associated companies 8,644 78,341  22,144 17,168 
Other 6,212 8,312  12,524 7,351 
Notes payable to associated companies — 225,975 
Accrued taxes 17,904 25,734  23,699 24,401 
Accrued interest 5,933 5,931 
Lease market valuation liability 36,900 36,900  36,900 36,900 
Other 44,745 29,273  18,060 23,145 
          
 114,613 404,757  119,448 115,095 
          
CAPITALIZATION:
  
Common stockholders’ equity- 
Common stockholder’s 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 178,170 178,181 
Other paid-in capital 178,157 178,182 
Accumulated other comprehensive loss  (48,179)  (49,803)  (46,642)  (49,183)
Retained earnings 112,310 214,490  100,937 117,534 
          
Total common stockholders’ equity 389,311 489,878 
Total common stockholder’s equity 379,462 393,543 
Noncontrolling interest 2,587 2,696  2,593 2,589 
          
Total equity 391,898 492,574  382,055 396,132 
Long-term debt and other long-term obligations 600,478 600,443  600,524 600,493 
          
 992,376 1,093,017  982,579 996,625 
          
NONCURRENT LIABILITIES:
  
Accumulated deferred income taxes 116,090 80,508  168,429 132,019 
Accumulated deferred investment tax credits 6,039 6,367  5,715 5,930 
Retirement benefits 67,953 65,988  51,764 71,486 
Asset retirement obligations 28,287 32,290  29,737 28,762 
Lease market valuation liability 208,525 236,200  180,850 199,300 
Other 64,179 64,151  65,012 65,089 
          
 491,073 485,504  501,507 502,586 
          
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
  
 $1,598,062 $1,983,278  $1,603,534 $1,614,306 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

15

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
                
 Nine Months Ended  Six Months Ended 
 September 30  June 30 
 2010 2009 
 (In thousands) 
(In thousands) 2011 2010 
  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income $27,821 $14,497  $17,408 $14,725 
Adjustments to reconcile net income to net cash from operating activities-  
Provision for depreciation 23,763 23,136  15,890 15,963 
Amortization (deferral) of regulatory assets, net  (3,708) 30,921 
Deferral of regulatory assets, net  (18,532)  (10,299)
Deferred rents and lease market valuation liability  (36,123)  (34,556)  (43,851)  (42,264)
Deferred income taxes and investment tax credits, net 18,927  (2,242) 41,457 16,503 
Accrued compensation and retirement benefits 4,529 3,039  1,085 2,600 
Accrued regulatory obligations  40  4,841   (1,193)  (632)
Electric service prepayment programs —  (1,458)
Pension trust contribution —  (21,590)  (45,000) — 
Cash collateral from suppliers 9,874 2,830 
Decrease in operating assets- 
Cash collateral from (to) suppliers, net  (14) 343 
Increase (decrease) in operating assets- 
Receivables 61,051 24,561   (48,807) 52,754 
Prepayments and other current assets 2,839 109   (9,758) 3,608 
Increase (decrease) in operating liabilities-  
Accounts payable  (69,846)  (13,440) 3,661  (61,195)
Accrued taxes  (6,172)  (5,057)  (701)  (4,007)
Accrued interest 10,050 14,033 
Other  (10,971)  (3,694) 5,771  (8,960)
          
Net cash provided from operating activities 32,074 35,930 
Net cash used for operating activities  (82,584)  (20,861)
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New Financing- 
Long-term debt — 297,422 
Redemptions and Repayments-  
Long-term debt  (167)  (292)  (105)  (111)
Short-term borrowings, net  (225,975)  (101,569) —  (225,975)
Common stock dividend payments  (130,000)  (25,000)  (34,000)  (130,000)
Other  (112)  (351)  (1,742)  (112)
          
Net cash provided from (used for) financing activities  (356,254) 170,210 
Net cash used for financing activities  (35,847)  (356,198)
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (29,592)  (33,005)  (17,386)  (20,237)
Leasehold improvement payments from associated companies 32,829 —  — 32,829 
Loan repayments from associated companies, net 3,847 10,256 
Loans to associated companies, net  (32,050)  (10,818)
Redemptions of lessor notes 20,509 18,358  21,739 20,485 
Sales of investment securities held in trusts 118,360 171,061  28,401 106,814 
Purchases of investment securities held in trusts  (119,777)  (173,214)  (30,050)  (107,978)
Other  (4,550)  (2,776)  (1,473)  (2,905)
          
Net cash provided from (used for) investing activities 21,626  (9,320)  (30,819) 18,190 
          
  
Net change in cash and cash equivalents  (302,554) 196,820   (149,250)  (358,869)
Cash and cash equivalents at beginning of period 436,712 14  149,262 436,712 
          
Cash and cash equivalents at end of period $134,158 $196,834  $12 $77,843 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

16

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                                
 Three Months Ended Nine Months Ended  Three Months Ended Six Months Ended 
 September 30 September 30  June 30 June 30 
(In thousands) 2011 2010 2011 2010 
 2010 2009 2010 2009  
 (In thousands) 
STATEMENTS OF INCOME
 
REVENUES:
  
Electric sales $952,420 $854,108 $2,353,418 $2,312,089  $576,977 $709,606 $1,211,000 $1,400,998 
Excise tax collections 16,080 14,128 39,444 37,890  11,120 11,012 23,607 23,364 
                  
Total revenues 968,500 868,236 2,392,862 2,349,979  588,097 720,618 1,234,607 1,424,362 
                  
  
EXPENSES:
  
Purchased power 556,618 509,035 1,381,104 1,414,226  328,463 410,470 698,631 824,486 
Other operating expenses 89,167 84,495 260,004 241,241  78,603 75,177 164,682 170,837 
Provision for depreciation 26,614 26,565 81,678 76,969  26,773 27,093 52,087 55,064 
Amortization of regulatory assets, net 100,476 96,051 251,250 262,900  40,046 81,326 121,633 150,774 
General taxes 19,974 18,344 51,312 48,427  15,115 14,902 32,526 31,338 
                  
Total expenses 792,849 734,490 2,025,348 2,043,763  489,000 608,968 1,069,559 1,232,499 
                  
  
OPERATING INCOME
 175,651 133,746 367,514 306,216  99,097 111,650 165,048 191,863 
                  
  
OTHER INCOME (EXPENSE):
  
Miscellaneous income 1,662 1,301 5,144 4,113  3,554 1,649 5,464 3,482 
Interest expense  (30,220)  (29,593)  (89,684)  (87,132)  (31,125)  (30,041)  (61,782)  (59,464)
Capitalized interest 199 139 488 419  618 156 1,045 289 
                  
Total other expense  (28,359)  (28,153)  (84,052)  (82,600)  (26,953)  (28,236)  (55,273)  (55,693)
                  
  
INCOME BEFORE INCOME TAXES
 147,292 105,593 283,462 223,616  72,144 83,414 109,775 136,170 
  
INCOME TAXES
 64,440 43,435 121,491 95,834  30,383 33,521 48,461 57,051 
                  
  
NET INCOME
 82,852 62,158 161,971 127,782  $41,761 $49,893 $61,314 $79,119 
                  
  
OTHER COMPREHENSIVE INCOME (LOSS):
 
STATEMENTS OF COMPREHENSIVE INCOME
 
 
NET INCOME
 $41,761 $49,893 $61,314 $79,119 
         
 
OTHER COMPREHENSIVE INCOME:
 
Pension and other postretirement benefits 4,135  (51,932) 24,198  (26,893) 4,290 4,135 8,511 20,063 
Unrealized gain on derivative hedges 69 69 207 207  69 69 138 138 
                  
Other comprehensive income (loss) 4,204  (51,863) 24,405  (26,686)
Income tax expense (benefit) related to other comprehensive income 1,443  (21,295) 9,442  (8,806)
Other comprehensive income 4,359 4,204 8,649 20,201 
Income tax expense related to other comprehensive income 1,612 1,441 3,202 7,999 
                  
Other comprehensive income (loss), net of tax 2,761  (30,568) 14,963  (17,880)
Other comprehensive income, net of tax 2,747 2,763 5,447 12,202 
                  
  
TOTAL COMPREHENSIVE INCOME
 $85,613 $31,590 $176,934 $109,902 
COMPREHENSIVE INCOME
 $44,508 $52,656 $66,761 $91,321 
                  
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

17

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                
 September 30, December 31,  June 30, December 31, 
 2010 2009 
(In thousands) 2011 2010 
 (In thousands)  
ASSETS
  
  
CURRENT ASSETS:
  
Cash and cash equivalents $1 $27  $42 $4 
Receivables-  
Customers (less accumulated provisions of $4,736,000 and $3,506,000, respectively, for uncollectible accounts) 378,822 300,991 
Customers, net of allowance for uncollectible accounts of $3,306 in 2011 and $3,769 in 2010 259,313 323,044 
Associated companies 3,900 12,884  66,069 53,780 
Other 26,024 21,877  25,580 26,119 
Notes receivable — associated companies 64,168 102,932  16,288 177,228 
Prepaid taxes 71,153 34,930  135,679 10,889 
Other 15,674 12,945  15,421 12,654 
          
 559,742 486,586  518,392 603,718 
          
UTILITY PLANT:
  
In service 4,568,640 4,463,490  4,589,369 4,562,781 
Less — Accumulated provision for depreciation 1,666,918 1,617,639  1,682,577 1,656,939 
          
 2,901,722 2,845,851  2,906,792 2,905,842 
Construction work in progress 51,857 54,251  112,573 63,535 
          
 2,953,579 2,900,102  3,019,365 2,969,377 
          
OTHER PROPERTY AND INVESTMENTS:
  
Nuclear fuel disposal trust 212,419 207,561 
Nuclear plant decommissioning trusts 175,254 166,768  190,422 181,851 
Nuclear fuel disposal trust 208,870 199,677 
Other 2,136 2,149  2,118 2,104 
          
 386,260 368,594  404,959 391,516 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Goodwill 1,810,936 1,810,936  1,810,936 1,810,936 
Regulatory assets 722,086 888,143  469,490 513,395 
Other 30,608 27,096  34,028 27,938 
          
 2,563,630 2,726,175  2,314,454 2,352,269 
          
 $6,463,211 $6,481,457  $6,257,170 $6,316,880 
          
LIABILITIES AND CAPITALIZATION
  
  
CURRENT LIABILITIES:
  
Currently payable long-term debt $31,947 $30,639  $33,315 $32,402 
Short-term borrowings- 
Associated companies 360,917 — 
Other 50,000 — 
Accounts payable-  
Associated companies 12,743 26,882  56,544 28,571 
Other 154,872 168,093  159,720 158,442 
Accrued compensation and benefits 35,578 35,232 
Customer deposits 23,684 23,385 
Accrued taxes 24,798 12,594  1,346 2,509 
Accrued interest 30,003 18,256  18,059 18,111 
Other 78,903 111,156  13,487 22,263 
          
 333,266 367,620  752,650 320,915 
          
CAPITALIZATION:
  
Common stockholders’ equity- 
Common stock, $10 par value, authorized 16,000,000 shares, 13,628,447 shares outstanding 136,284 136,284 
Common stockholder’s equity- 
Common stock, $10 par value, authorized 16,000,000 shares- 13,628,447 shares outstanding 136,284 136,284 
Other paid-in capital 2,508,852 2,507,049  2,008,847 2,508,874 
Accumulated other comprehensive loss  (228,049)  (243,012)  (248,095)  (253,542)
Retained earnings 197,046 200,075  288,484 227,170 
          
Total common stockholders’ equity 2,614,133 2,600,396 
Total common stockholder’s equity 2,185,520 2,618,786 
Long-term debt and other long-term obligations 1,779,081 1,801,589  1,754,582 1,769,849 
          
 4,393,214 4,401,985  3,940,102 4,388,635 
          
NONCURRENT LIABILITIES:
  
Accumulated deferred income taxes 720,825 687,545  761,844 715,527 
Power purchase contract liability 239,943 233,492 
Nuclear fuel disposal costs 196,703 196,511  196,868 196,768 
Retirement benefits 133,579 150,603  71,711 182,364 
Asset retirement obligations 106,573 101,568  111,831 108,297 
Power purchase contract liability 386,273 399,105 
Other 192,778 176,520  182,221 170,882 
          
 1,736,731 1,711,852  1,564,418 1,607,330 
          
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
  
 $6,463,211 $6,481,457  $6,257,170 $6,316,880 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

18

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
                
 Nine Months Ended  Six Months Ended 
 September 30  June 30 
 2010 2009 
 (In thousands) 
(In thousands) 2011 2010 
  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income $161,971 $127,782  $61,314 $79,119 
Adjustments to reconcile net income to net cash from operating activities-  
Provision for depreciation 81,678 76,969  52,087 55,064 
Amortization of regulatory assets, net 251,250 262,900  121,633 150,774 
Deferred purchased power and other costs  (85,136)  (106,340)  (70,998)  (67,664)
Deferred income taxes and investment tax credits, net 14,984 40,989  51,222  (1,425)
Accrued compensation and retirement benefits 11,621 7,308  1,319 2,608 
Cash collateral paid, net  (23,400)  (210)  (235)  (23,400)
Pension trust contribution —  (100,000)  (105,000) — 
Decrease (increase) in operating assets-  
Receivables  (72,994) 18,984  58,466  (46,788)
Prepayments and other current assets  (36,573)  (83,538)
Prepaid taxes  (124,790)  (111,968)
Increase (decrease) in operating liabilities-  
Accounts payable  (37,668)  (40,670) 13,856 11,924 
Accrued taxes 35,326  (13,399)  (1,167) 10,368 
Accrued interest 11,747 20,946 
Tax collections payable —  (9,714)
Other  (13,953) 12,606  612  (6,446)
          
Net cash provided from operating activities 298,853 214,613  58,319 52,166 
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New Financing-  
Short-term borrowings, net 410,917 57,850 
Redemptions and Repayments- 
Long-term debt — 299,619   (14,671)  (13,830)
Redemptions and Repayments- 
Common stock —  (150,000)
Long-term debt  (21,703)  (20,570)
Short-term borrowings, net —  (114,766)
Common stock dividend payments  (165,000)  (88,000) —  (90,000)
Equity payment to parent  (500,000) — 
Other  (2)  (2,275)  (1,452) — 
          
Net cash used for financing activities  (186,705)  (75,992)  (105,206)  (45,980)
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (130,008)  (121,342)  (98,153)  (80,727)
Loans from (to) associated companies, net 38,764  (660)
Loans to associated companies, net 160,940 85,049 
Sales of investment securities held in trusts 340,368 338,684  375,885 281,242 
Purchases of investment securities held in trusts  (353,028)  (351,216)  (385,448)  (289,454)
Other  (8,270)  (4,152)  (6,299)  (2,224)
          
Net cash used for investing activities  (112,174)  (138,686)
Net cash provided from (used for) investing activities 46,925  (6,114)
          
  
Net change in cash and cash equivalents  (26)  (65) 38 72 
Cash and cash equivalents at beginning of period 27 66  4 27 
          
Cash and cash equivalents at end of period $1 $1  $42 $99 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

19

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                                
 Three Months Ended Nine Months Ended  Three Months Ended Six Months Ended 
 September 30 September 30  June 30 June 30 
 2010 2009 2010 2009 
(In thousands) 2011 2010 2011 2010 
 (In thousands) 
REVENUES:
  
Electric sales $460,864 $424,901 $1,334,454 $1,194,609  $265,363 $422,030 $603,779 $873,590 
Gross receipts tax collections 23,049 20,612 65,245 58,181  14,601 20,629 33,401 42,196 
                  
Total revenues 483,913 445,513 1,399,699 1,252,790  279,964 442,659 637,180 915,786 
                  
  
EXPENSES:
  
Purchased power from affiliates 166,039 94,768 476,119 273,497  34,935 149,000 84,824 310,080 
Purchased power from non-affiliates 87,561 142,495 264,765 389,705  100,836 85,276 253,879 177,204 
Other operating expenses 141,761 63,654 333,895 221,320  50,075 90,151 97,307 192,134 
Provision for depreciation 12,978 13,262 39,176 38,320  12,766 13,440 25,189 26,198 
Amortization of regulatory assets, net 15,480 84,631 112,869 173,770  22,167 48,589 54,261 97,389 
General taxes 25,029 22,540 66,663 66,509  17,152 19,894 39,302 41,634 
                  
Total expenses 448,848 421,350 1,293,487 1,163,121  237,931 406,350 554,762 844,639 
                  
  
OPERATING INCOME
 35,065 24,163 106,212 89,669  42,033 36,309 82,418 71,147 
                  
 
OTHER INCOME (EXPENSE):
  
Interest income 581 2,169 2,678 8,124  13 880 106 2,097 
Miscellaneous income 1,539 1,068 5,093 2,982  915 1,381 1,885 3,554 
Interest expense  (13,037)  (14,380)  (39,812)  (42,502)  (13,130)  (13,002)  (26,187)  (26,775)
Capitalized interest 176 47 461 124  228 159 375 285 
                  
Total other expense  (10,741)  (11,096)  (31,580)  (31,272)  (11,974)  (10,582)  (23,821)  (20,839)
                  
  
INCOME BEFORE INCOME TAXES
 24,324 13,067 74,632 58,397  30,059 25,727 58,597 50,308 
  
INCOME TAXES
 10,084 2,324 30,968 21,027  13,281 8,618 19,232 20,884 
                  
  
NET INCOME
 14,240 10,743 43,664 37,370  $16,778 $17,109 $39,365 $29,424 
                  
  
OTHER COMPREHENSIVE INCOME (LOSS):
 
STATEMENTS OF COMPREHENSIVE INCOME
 
 
NET INCOME
 $16,778 $17,109 $39,365 $29,424 
         
 
OTHER COMPREHENSIVE INCOME
 
Pension and other postretirement benefits 2,161  (31,365) 14,032 557  2,227 2,162 4,190 11,871 
Unrealized gain on derivative hedges 84 84 252 252  84 84 168 168 
                  
Other comprehensive income (loss) 2,245  (31,281) 14,284 809 
Income tax expense (benefit) related to other comprehensive income 723  (13,112) 5,624 2,273 
Other comprehensive income 2,311 2,246 4,358 12,039 
Income tax expense related to other comprehensive income 869 724 1,632 4,901 
                  
Other comprehensive income (loss), net of tax 1,522  (18,169) 8,660  (1,464)
Other comprehensive income, net of tax 1,442 1,522 2,726 7,138 
                  
  
TOTAL COMPREHENSIVE INCOME (LOSS)
 $15,762 $(7,426) $52,324 $35,906 
COMPREHENSIVE INCOME
 $18,220 $18,631 $42,091 $36,562 
                  
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

20

METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                
 September 30, December 31,  June 30, December 31, 
 2010 2009 
 (In thousands) 
(In thousands) 2011 2010 
ASSETS
  
  
CURRENT ASSETS:
  
Cash and cash equivalents $124 $120  $157 $243,220 
Receivables-  
Customers (less accumulated provisions of $4,344,000 and $4,044,000, respectively, for uncollectible accounts) 182,509 171,052 
Customers, net of allowance for uncollectible accounts of $3,087 in 2011 and $3,868 in 2010 143,820 178,522 
Associated companies 41,689 29,413  12,849 24,920 
Other 13,654 11,650  16,437 13,007 
Notes receivable from associated companies 11,201 97,150  10,432 11,028 
Prepaid taxes 27,307 15,229  27,083 343 
Other 2,523 1,459  1,443 2,289 
          
 279,007 326,073  212,221 473,329 
          
UTILITY PLANT:
  
In service 2,213,765 2,162,815  2,266,437 2,247,853 
Less — Accumulated provision for depreciation 836,821 810,746  859,055 846,003 
          
 1,376,944 1,352,069  1,407,382 1,401,850 
Construction work in progress 31,488 14,901  42,604 23,663 
          
 1,408,432 1,366,970  1,449,986 1,425,513 
          
OTHER PROPERTY AND INVESTMENTS:
  
Nuclear plant decommissioning trusts 277,823 266,479  301,188 289,328 
Other 877 890  840 884 
          
 278,700 267,369  302,028 290,212 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Goodwill 416,499 416,499  416,499 416,499 
Regulatory assets 400,375 356,754  341,488 295,856 
Power purchase contract asset 103,902 176,111  65,861 111,562 
Other 64,084 36,544  54,587 31,699 
          
 984,860 985,908  878,435 855,616 
          
 $2,950,999 $2,946,320  $2,842,670 $3,044,670 
          
LIABILITIES AND CAPITALIZATION
  
  
CURRENT LIABILITIES:
  
Currently payable long-term debt $28,500 $128,500  $28,760 $28,760 
Short-term borrowings-  
Associated companies 6,296 —  238,399 124,079 
Other 50,000 — 
Accounts payable-  
Associated companies 34,204 40,521  24,377 33,942 
Other 28,604 41,050  48,262 29,862 
Accrued taxes 2,967 11,170  12,844 60,856 
Accrued interest 11,717 17,362  16,011 16,114 
Other 31,993 24,520  29,605 29,278 
          
 144,281 263,123  448,258 322,891 
          
CAPITALIZATION:
  
Common stockholders’ equity- 
Common stock, without par value, authorized 900,000 shares, 859,500 shares outstanding 1,197,064 1,197,070 
Common stockholder’s equity- 
Common stock, without par value, authorized 900,000 shares, 740,905 and 859,500 shares outstanding, respectively 842,023 1,197,076 
Accumulated other comprehensive loss  (134,891)  (143,551)  (139,657)  (142,383)
Retained earnings 48,064 4,399  46,772 32,406 
          
Total common stockholders’ equity 1,110,237 1,057,918 
Total common stockholder’s equity 749,138 1,087,099 
Long-term debt and other long-term obligations 713,941 713,873  704,486 718,860 
          
 1,824,178 1,771,791  1,453,624 1,805,959 
          
NONCURRENT LIABILITIES:
  
Accumulated deferred income taxes 489,608 453,462  494,716 473,009 
Accumulated deferred investment tax credits 6,978 7,313  6,656 6,866 
Nuclear fuel disposal costs 44,434 44,391  44,471 44,449 
Asset retirement obligations 199,162 192,659 
Retirement benefits 28,268 33,605  22,276 29,121 
Asset retirement obligations 189,489 180,297 
Power purchase contract liability 175,259 143,135  121,924 116,027 
Other 48,504 49,203  51,583 53,689 
          
 982,540 911,406  940,788 915,820 
          
COMMITMENTS AND CONTINGENCIES (Note 9)
        
 $2,950,999 $2,946,320  $2,842,670 $3,044,670 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

21

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
                
 Nine Months Ended  Six Months Ended 
 September 30  June 30 
 2010 2009 
 (In thousands) 
(In thousands) 2011 2010 
  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income $43,664 $37,370  $39,365 $29,424 
Adjustments to reconcile net income to net cash from operating activities-  
Provision for depreciation 39,176 38,320  25,189 26,198 
Amortization of regulatory assets, net 112,869 173,770  54,261 97,389 
Deferred costs recoverable as regulatory assets  (49,646)  (70,044)  (41,699)  (38,358)
Deferred income taxes and investment tax credits, net 23,781 59,393  11,972  (12,079)
Accrued compensation and retirement benefits  (282) 6,712   (510)  (1,573)
Cash collateral from suppliers, net 174 50 
Pension trust contribution —  (123,521)  (35,000) — 
Cash collateral paid, net  (17,647)  (6,800)
Decrease (increase) in operating assets-  
Receivables  (18,444)  (23,370) 46,240  (29,439)
Prepayments and other current assets  (13,144)  (22,614)
Prepaid taxes  (26,740)  (31,246)
Increase (decrease) in operating liabilities-  
Accounts payable  (18,763)  (17,293) 5,148 733 
Accrued taxes  (8,203)  (11,095)  (47,676) 9,519 
Accrued interest  (5,645) 5,001   (103)  (1,277)
Other 7,721 11,891  10,903 7,553 
          
Net cash provided from operating activities 95,437 57,720  41,524 56,894 
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New Financing-  
Long-term debt — 300,000 
Short-term borrowings, net 6,296 —  164,320 17,898 
Redemptions and Repayments-  
Common stock  (150,000) — 
Long-term debt  (100,000) —   (14,784)  (100,000)
Short-term borrowings, net —  (265,003)
Other —  (2,268)
Common stock dividend payments  (80,000) — 
Equity payment to parent  (150,000) — 
          
Net cash provided from (used for) financing activities  (93,704) 32,729 
Net cash used for financing activities  (230,464)  (82,102)
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (77,921)  (73,106)  (46,647)  (54,405)
Sales of investment securities held in trusts 420,116 88,802  501,260 376,610 
Purchases of investment securities held in trusts  (427,150)  (95,982)  (506,220)  (381,219)
Loans from (to) associated companies, net 85,949  (6,586)
Loans to associated companies, net 596 85,943 
Other  (2,723)  (3,597)  (3,112)  (1,715)
          
Net cash used for investing activities  (1,729)  (90,469)
Net cash provided from (used for) investing activities  (54,123) 25,214 
          
  
Net change in cash and cash equivalents 4  (20)  (243,063) 6 
Cash and cash equivalents at beginning of period 120 144  243,220 120 
          
Cash and cash equivalents at end of period $124 $124  $157 $126 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

22

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                                
 Three Months Ended Nine Months Ended  Three Months Ended Six Months Ended 
 September 30 September 30  June 30 June 30 
(In thousands) 2011 2010 2011 2010 
 2010 2009 2010 2009  
 (In thousands) 
STATEMENTS OF INCOME
 
REVENUES:
  
Electric sales $372,480 $340,246 $1,108,751 $1,028,420  $238,942 $350,335 $547,258 $736,271 
Gross receipts tax collections 17,414 15,246 51,100 47,342  12,727 16,162 29,256 33,686 
                  
Total revenues 389,894 355,492 1,159,851 1,075,762  251,669 366,497 576,514 769,957 
                  
  
EXPENSES:
  
Purchased power from affiliates 165,125 81,191 486,470 249,438  54,635 152,945 102,119 321,345 
Purchased power from non-affiliates 92,648 144,777 270,900 397,260  64,459 86,829 205,895 178,252 
Other operating expenses 58,832 47,785 198,296 171,375  44,570 67,070 85,898 139,464 
Provision for depreciation 14,859 15,038 46,146 45,074  15,770 16,605 30,343 31,287 
Amortization (deferral) of regulatory assets, net  (1,771) 17,201  (22,259) 44,090  12,608  (10,522) 25,615  (20,488)
General taxes 19,194 17,230 54,375 56,074  14,665 18,647 35,401 35,181 
                  
Total expenses 348,887 323,222 1,033,928 963,311  206,707 331,574 485,271 685,041 
                  
  
OPERATING INCOME
 41,007 32,270 125,923 112,451  44,962 34,923 91,243 84,916 
                  
  
OTHER INCOME (EXPENSE):
  
Miscellaneous income 1,508 1,156 4,431 2,865  644 1,310 669 2,923 
Interest expense  (17,581)  (11,614)  (52,501)  (36,690)  (17,361)  (17,630)  (34,595)  (34,920)
Capitalized interest 193 23 516 74  41 183 63 323 
                  
Total other expense  (15,880)  (10,435)  (47,554)  (33,751)  (16,676)  (16,137)  (33,863)  (31,674)
                  
  
INCOME BEFORE INCOME TAXES
 25,127 21,835 78,369 78,700  28,286 18,786 57,380 53,242 
  
INCOME TAXES
 5,311 6,039 28,280 29,393  13,568 5,812 25,356 22,969 
                  
  
NET INCOME
 19,816 15,796 50,089 49,307  $14,718 $12,974 $32,024 $30,273 
                  
  
OTHER COMPREHENSIVE INCOME (LOSS):
 
STATEMENTS OF COMPREHENSIVE INCOME
 
 
NET INCOME
 $14,718 $12,974 $32,024 $30,273 
         
 
OTHER COMPREHENSIVE INCOME:
 
Pension and other postretirement benefits 1,830  (79,579) 12,207  (47,224) 1,890 1,830 3,475 10,377 
Unrealized gain on derivative hedges 16 17 48 49  17 16 33 32 
Change in unrealized gain on available-for-sale securities — 19 — 3 
                  
Other comprehensive income (loss) 1,846  (79,543) 12,255  (47,172)
Income tax expense (benefit) related to other comprehensive income 484  (33,141) 4,251  (16,986)
Other comprehensive income 1,907 1,846 3,508 10,409 
Income tax expense related to other comprehensive income 678 483 1,233 3,767 
                  
Other comprehensive income (loss), net of tax 1,362  (46,402) 8,004  (30,186)
Other comprehensive income, net of tax 1,229 1,363 2,275 6,642 
                  
  
TOTAL COMPREHENSIVE INCOME (LOSS)
 $21,178 $(30,606) $58,093 $19,121 
COMPREHENSIVE INCOME
 $15,947 $14,337 $34,299 $36,915 
                  
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

23

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                
 September 30, December 31,  June 30, December 31, 
 2010 2009 
(In thousands) 2011 2010 
 (In thousands)  
ASSETS
  
  
CURRENT ASSETS:
  
Cash and cash equivalents $8 $14  $2 $5 
Receivables-  
Customers (less accumulated provisions of $3,481,000 and $3,483,000, respectively, for uncollectible accounts) 135,416 139,302 
Customers, net of allowance for uncollectible accounts of $2,856 in 2011 and $3,369 in 2010 121,511 148,864 
Associated companies 95,355 77,338  65,989 54,052 
Other 14,413 18,320  11,420 11,314 
Notes receivable from associated companies 14,569 14,589  13,498 14,404 
Prepaid taxes 48,264 18,946  26,372 14,026 
Other 2,115 1,400  1,423 1,592 
          
 310,140 269,909  240,215 244,257 
          
UTILITY PLANT:
  
In service 2,503,555 2,431,737  2,552,303 2,532,629 
Less — Accumulated provision for depreciation 925,894 901,990  947,315 935,259 
          
 1,577,661 1,529,747  1,604,988 1,597,370 
Construction work in progress 28,498 24,205  62,592 30,505 
          
 1,606,159 1,553,952  1,667,580 1,627,875 
          
OTHER PROPERTY AND INVESTMENTS:
  
Nuclear plant decommissioning trusts 147,675 142,603  162,154 152,928 
Non-utility generation trusts 92,034 120,070  126,786 80,244 
Other 294 289  292 297 
          
 240,003 262,962  289,232 233,469 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Goodwill 768,628 768,628  768,628 768,628 
Regulatory assets 202,801 9,045  222,804 163,407 
Power purchase contract asset 5,746 15,362  4,000 5,746 
Other 28,780 19,143  15,272 19,287 
          
 1,005,955 812,178  1,010,704 957,068 
          
 $3,162,257 $2,899,001  $3,207,731 $3,062,669 
          
LIABILITIES AND CAPITALIZATION
  
  
CURRENT LIABILITIES:
  
Currently payable long-term debt $69,310 $69,310  $45,000 $45,000 
Short-term borrowings-  
Associated companies 43,244 41,473  159,902 101,338 
Accounts payable-  
Associated companies 40,747 39,884  77,121 35,626 
Other 28,427 41,990  29,217 41,420 
Accrued taxes 4,164 6,409  3,397 5,075 
Accrued interest 24,513 17,598  17,454 17,378 
Other 25,871 22,741  23,280 22,541 
          
 236,276 239,405  355,371 268,378 
          
CAPITALIZATION:
  
Common stockholders’ equity- 
Common stock, $20 par value, authorized 5,400,000 shares, 4,427,577 shares outstanding 88,552 88,552 
Common stockholder’s equity- 
Common stock, $20 par value, authorized 5,400,000 shares- 4,427,577 shares outstanding 88,552 88,552 
Other paid-in capital 913,507 913,437  913,486 913,519 
Accumulated other comprehensive loss  (154,100)  (162,104)  (161,251)  (163,526)
Retained earnings 141,590 91,501  23,017 60,993 
          
Total common stockholders’ equity 989,549 931,386 
Total common stockholder’s equity 863,804 899,538 
Long-term debt and other long-term obligations 1,072,207 1,072,181  1,072,417 1,072,262 
          
 2,061,756 2,003,567  1,936,221 1,971,800 
          
NONCURRENT LIABILITIES:
  
Accumulated deferred income taxes 356,536 242,040  415,899 371,877 
Retirement benefits 167,542 174,306  188,407 187,621 
Power purchase contract liability 160,130 116,972 
Asset retirement obligations 96,519 91,841  101,441 98,132 
Power purchase contract liability 194,102 100,849 
Other 49,526 46,993  50,262 47,889 
          
 864,225 656,029  916,139 822,491 
          
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
     
 $3,162,257 $2,899,001  $3,207,731 $3,062,669 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

24

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
                
 Nine Months Ended  Six Months Ended 
 September 30  June 30 
 2010 2009 
 (In thousands) 
(In thousands) 2011 2010 
  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income $50,089 $49,307  $32,024 $30,273 
Adjustments to reconcile net income to net cash from operating activities-  
Provision for depreciation 46,146 45,074  30,343 31,287 
Amortization (deferral) of regulatory assets, net  (22,259) 44,090  25,615  (20,488)
Deferred costs recoverable as regulatory assets  (61,574)  (76,953)  (38,291)  (38,955)
Deferred income taxes and investment tax credits, net 94,015 56,144  46,687 42,943 
Accrued compensation and retirement benefits 7,634 6,271  4,733 4,216 
Cash collateral paid, net  (11,760) —   (1,276)  (3,613)
Pension trust contribution —  (60,000)
Decrease (increase) in operating assets-  
Receivables  (2,584) 3,687  19,561 3,266 
Prepayments and other current assets  (30,034)  (24,730)
Prepaid taxes  (12,346)  (37,504)
Increase (decrease) in operating liabilities-  
Accounts payable  (12,766)  (8,988) 23,449  (4,603)
Accrued taxes  (2,245)  (7,015)  (12,373)  (1,339)
Accrued interest 6,915  (2,570)
Other 10,127 13,392  13,153 10,227 
          
Net cash provided from operating activities 71,704 37,709  131,279 15,710 
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New Financing-  
Long-term debt — 498,583  25,000 — 
Short-term borrowings, net 1,771 —  58,564 25,313 
Redemptions and Repayments-  
Long-term debt —  (100,000)  (25,000) — 
Short-term borrowings, net —  (239,770)
Common stock dividend payments —  (85,000)  (70,000) — 
Other  (125)  (3,865)  (1,353) 5 
          
Net cash provided from financing activities 1,646 69,948 
Net cash provided from (used for) financing activities  (12,789) 25,318 
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (91,924)  (92,070)  (64,177)  (58,293)
Loans to associated companies, net 906 498 
Sales of investment securities held in trusts 141,392 80,986  265,223 133,934 
Purchases of investment securities held in trusts  (116,240)  (91,105)  (314,738)  (113,067)
Other  (6,584)  (5,482)  (5,707)  (4,104)
          
Net cash used for investing activities  (73,356)  (107,671)  (118,493)  (41,032)
          
  
Net change in cash and cash equivalents  (6)  (14)  (3)  (4)
Cash and cash equivalents at beginning of period 14 23  5 14 
          
Cash and cash equivalents at end of period $8 $9  $2 $10 
          
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

25

FIRSTENERGY CORP. AND SUBSIDIARIES
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
       
Note   Page 
Number   Number 
       
1
 Organization and Basis of Presentation  27 
       
2
 Merger  27 
       
3
 Earnings Per Share  31 
       
4
 Fair Value of Instruments  31 
       
5
 Derivative Instruments  45 
       
6
 Pension Benefits and Other Postretirement Benefits  50 
       
7
 Variable Interest Entities  52 
       
8
 Income Taxes  53 
       
9
 Commitments, Guarantees and Contingencies  54 
       
10
 Regulatory Matters  61 
       
11
 Stock-Based Compensation Plans  70 
       
12
 New Accounting Standards and Interpretations  72 
       
13
 Segment Information  72 
       
14
 Impairment of Long-Lived Assets  74 
       
15
 Asset Retirement Obligations  75 
       
16
 Supplemental Guarantor Information  75 

26

COMBINED NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
1. ORGANIZATION AND BASIS OF PRESENTATION
FirstEnergy is a diversified energy company that holds, directly or indirectly, all of the outstanding common stock of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), ATSI, JCP&L, Met-Ed, Penelec, FENOC, AE and its principal subsidiaries (AE Supply, AGC, MP, PE, WP and TrAIL), FES and its subsidiaries FGCO and NGC, and FESC. AE merged with a subsidiary of FirstEnergy on February 25, 2011, with AE continuing as the surviving corporation and becoming a wholly-owned subsidiary of FirstEnergy (See Note 2, Merger).
FirstEnergy and its subsidiaries follow GAAP and comply with the related regulations, orders, policies and practices prescribed by the SEC, the FERC, and, as applicable, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC and the NJBPU. These unaudited interim financial statements and notes were prepared in accordance with GAAP for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. 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 unaudited interim financial statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K for the year ended December 31, 20092010 for FirstEnergy, FES and the Utilities,Utility Registrants, as applicable. The consolidated unaudited financial statements of FirstEnergy, FES and each of the UtilitiesUtility Registrants reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain prior year amounts have been reclassified to conform to the current year presentation. Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.
FirstEnergy and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary (see Note 7)7, Variable Interest Entities). Investments in affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but with respect to which are not the primary beneficiary and do not exercise control, follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage share of the entity’s earnings is reported in the Consolidated Statements of Income.
2. MERGER
Merger
On February 25, 2011, the merger between FirstEnergy and Allegheny closed. Pursuant to the terms of the Agreement and Plan of Merger among FirstEnergy, Element Merger Sub, Inc., a Maryland corporation and a wholly-owned subsidiary of FirstEnergy (Merger Sub) and AE, Merger Sub merged with and into AE, with AE continuing as the surviving corporation and becoming a wholly-owned subsidiary of FirstEnergy. As part of the merger, AE shareholders received 0.667 of a share of FirstEnergy common stock for each share of AE common stock outstanding as of the date the merger was completed, and all outstanding AE equity-based employee compensation awards were converted into FirstEnergy equity-based awards on the same basis.
The total consideration in the merger was based on the closing price of a share of FirstEnergy common stock on February 24, 2011, the day prior to the date the merger was completed, and was calculated as follows (in millions, except per share data):
     
Shares of Allegheny common stock outstanding on February 24, 2011  170 
Exchange ratio  0.667 
    
Number of shares of FirstEnergy common stock issued  113 
Closing price of FirstEnergy common stock on February 24, 2011 $38.16 
    
Fair value of shares issued by FirstEnergy $4,327 
Fair value of replacement share-based compensation awards relating to pre-merger service  27 
    
Total consideration transferred $4,354 
    

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The allocation of the total consideration transferred to the assets acquired and liabilities assumed includes adjustments for the fair value of coal contracts, energy supply contracts, emission allowances, unregulated property, plant and equipment, derivative instruments, goodwill, intangible assets, long-term debt and accumulated deferred income taxes. The preliminary allocation of the purchase price is as follows:
     
(In millions)    
     
Current assets $1,494 
Property, plant and equipment  9,656 
Investments  138 
Goodwill  881 
Other noncurrent assets  1,347 
Current liabilities  (716)
Noncurrent liabilities  (3,452)
Long-term debt and other long-term obligations  (4,994)
    
  $4,354 
    
The allocation of purchase price in the table above reflects a refinement made during the quarter ended June 30, 2011 in the determination of the fair values of income tax benefits, certain coal contracts and an adverse purchase power contract. This resulted in an increase in noncurrent assets of approximately $85 million and decreases in current assets and goodwill of $15 million and $71 million, respectively. The impact of the refinements on the amortization of purchase accounting adjustments recorded during the quarter ended March 31, 2011 was not significant. Further modifications to the purchase price allocation may occur as a result of continuing review of the assets acquired and liabilities assumed.
The estimated fair values of the assets acquired and liabilities assumed have been determined based on the accounting guidance for fair value measurements under GAAP, which defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.
The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. The Allegheny delivery, transmission and generation businesses have been assigned to the Regulated Distribution, Regulated Independent Transmission and Competitive Energy Services segments, respectively. The preliminary estimate of goodwill from the merger of $881 million has been assigned to the Competitive Energy Services segment based on expected synergies from the merger. The goodwill is not deductible for tax purposes.
Total goodwill recognized by segment in FirstEnergy’s Consolidated Balance Sheet is as follows:
                     
      Competitive  Regulated       
  Regulated  Energy  Independent  Other/    
(In millions) Distribution  Services  Transmission  Corporate  Consolidated 
                     
Balance as of December 31, 2010 $5,551  $24  $—  $—  $5,575 
                     
Merger with Allegheny  —   881   —   —   881 
                
                     
Balance as of June 30, 2011 $5,551  $905  $—  $—  $6,456 
                

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The preliminary valuation of the additional intangible assets and liabilities recorded as result of the merger is as follows:
         
  Preliminary  Weighted Average 
(In millions) Valuation  Amortization Period 
Above market contracts:        
Energy contracts $189  10 years
NUG contracts  124  25 years
Coal supply contracts  516  8 years
        
   829     
         
Below market contracts:        
NUG contracts  143  13 years
Coal supply contracts  83  7 years
Transportation contract  35  8 years
        
   261     
        
         
Net intangible assets $568     
        
The fair value measurements of intangible assets and liabilities were based on significant unobservable inputs and thus represent level 3 measurements as defined in accounting guidance for fair value measurements.
The fair value of Allegheny’s energy, NUG and gas transportation contracts, both above-market and below-market, were estimated based on the present value of the above/below market cash flows attributable to the contracts based on the contract type, discounted by a current market interest rate consistent with the overall credit quality of the portfolio. The above/below market cash flows were estimated by comparing the expected cash flow based on existing contracted prices and expected volumes with the cash flows from estimated current market contract prices for the same expected volumes. The estimated current market contract prices were derived considering current market prices, such as the price of energy and transmission, miscellaneous fees and a normal profit margin. The weighted average amortization period was determined based on the expected volumes to be delivered over the life of the contract.
The fair value of coal supply contracts was determined in a similar manner based on the present value of the above/below market cash flows attributable to the contracts. The fair value adjustment for these contracts is being amortized based on expected deliveries under each contract.
As of June 30, 2011, intangible assets on FirstEnergy’s Consolidated Balance Sheet, including those recorded in connection with the merger, include the following:
     
  Intangible 
(In millions) Assets 
Purchase contract assets    
NUG $198 
OVEC  54 
    
   252 
     
Intangible assets    
Coal contracts  487 
FES customer intangible assets  129 
Energy contracts  105 
    
   721 
    
     
Total intangible assets $973 
    
Acquired land easements and software with a fair value of $169 million are included in “Property, plant and equipment” on FirstEnergy’s Consolidated Balance Sheet as of June 30, 2011.
In connection with the merger, FirstEnergy recorded merger transaction costs of approximately $7 million ($5 million net of tax) and $7 million ($5 million net of tax) during the three months ended June 30, 2011 and 2010, respectively and approximately $89 million ($72 million net of tax) and $21 million ($15 million net of tax) during the first six months of 2011 and 2010, respectively. These costs are included in “Other operating expenses” in the Consolidated Statements of Income. Merger transaction costs recognized in the first six months of 2011 include $56 million ($47 net of tax) of change in control and other benefit payments to AE executives.

29

FirstEnergy also recorded approximately $10 million ($6 million net of tax) and $85 million ($66 million net of tax) in merger integration costs during the three and six months ended June 30 2011, respectively, including an inventory valuation adjustment. In connection with the merger, FirstEnergy reviewed its inventory levels as a result of combining the inventory of both companies. Following this review, FirstEnergy management determined that the combined inventory stock contained excess and duplicative items. FirstEnergy management also adopted a consistent excess and obsolete inventory practice for the combined entity. Application of the revised practice, in conjunction with those items identified as excess and duplicative, resulted in an inventory valuation adjustment of $67 million ($42 million net of tax) in the first quarter of 2011.
Revenues and earnings of Allegheny included in FirstEnergy’s Consolidated Statement of Income for the periods subsequent to the February 25, 2011 merger date are as follows:
         
 April 1 –  February 26 – 
(In millions, except per share amounts) June 30, 2011  June 30, 2011 
         
Total revenues
 $1,181  $1,618 
Earnings available to FirstEnergy Corp.(1)
  63   17 
         
Basic Earnings Per Share
 $0.15  $0.04 
Diluted Earnings Per Share
 $0.15  $0.04 
(1)Includes Allegheny’s after-tax merger costs of $4 million and $56 million, respectively.
Pro Forma Financial Information
The following unaudited pro forma financial information reflects the consolidated results of operations of FirstEnergy as if the merger with Allegheny had taken place on January 1, 2010. The unaudited pro forma information has been calculated after applying FirstEnergy’s accounting policies and adjusting Allegheny’s results to reflect the depreciation and amortization that would have been charged assuming fair value adjustments to property, plant and equipment, debt and intangible assets had been applied on January 1, 2010, together with the consequential tax effects.
FirstEnergy and Allegheny both incurred non-recurring costs directly related to the merger that have been included in the pro forma earnings presented below. Combined pre-tax transaction costs incurred were approximately $7 million and $11 million in the three months ended June 30, 2011 and 2010, respectively, and approximately $90 million and $39 million in the six months ended June 30, 2011 and 2010, respectively. In addition, during the six months ended June 30, 2011, $85 million of pre-tax merger integration costs and $32 million of charges from merger settlements approved by regulatory agencies were recognized. Charges resulting from merger settlements are not expected to be material in future periods.
The unaudited pro forma financial information has been presented below for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved or the future consolidated results of operations of the combined company.
                 
  Three Months Ended  Six Months Ended 
(Pro forma amounts in millions, except June 30  June 30 
per share amounts) 2011  2010  2011  2010 
                 
Revenues
 $4,062  $4,401  $8,848  $9,086 
Earnings available to FirstEnergy
 $186  $389  $323  $644 
                 
Basic Earnings Per Share
 $0.44  $0.93  $0.77  $1.54 
             
Diluted Earnings Per Share
 $0.44  $0.93  $0.77  $1.53 
             

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3. EARNINGS PER SHARE
Basic earnings per share of common stock isare computed using the weighted average of actual common shares outstanding during the respectiverelevant period as the denominator. The denominator for diluted earnings per share of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could resultwould be issued if dilutive securities and other agreements to issue common stock were exercised. The following table reconciles basic and diluted earnings per share of common stock:
                                
 Three Months Nine Months  Three Months Six Months 
Reconciliation of Basic and Diluted Earnings per Share Ended September 30 Ended September 30  Ended June 30 Ended June 30 
of Common Stock 2010 2009 2010 2009  2011 2010 2011 2010 
 (In millions, except per share amounts)  (In millions, except per share amounts) 
  
Earnings available to FirstEnergy Corp. $179 $234 $599 $768  $181 $265 $231 $420 
                  
 
Weighted average number of basic shares outstanding 304 304 304 304 
Weighted average number of basic shares outstanding(1)
 418 304 380 304 
Assumed exercise of dilutive stock options and awards 1 2 1 2  2 1 2 1 
                  
Weighted average number of diluted shares outstanding 305 306 305 306 
Weighted average number of diluted shares outstanding(1)
 420 305 382 305 
                  
  
Basic earnings per share of common stock $0.59 $0.77 $1.97 $2.52  $0.43 $0.87 $0.61 $1.38 
                  
Diluted earnings per share of common stock $0.59 $0.77 $1.96 $2.51  $0.43 $0.87 $0.61 $1.37 
                  

26

(1)Includes 113 million shares issued to AE stockholders for the periods subsequent to the merger date. (See Note 2)

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 INSTRUMENTSMEASUREMENTS
(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.”borrowings”. The following table provides the approximate fair value and related carrying amounts of long-term debt and other long-term obligations as of SeptemberJune 30, 20102011 and December 31 2009:2010:
                                
 September 30, 2010 December 31, 2009  June 30, 2011 December 31, 2010 
 Carrying Fair Carrying Fair  Carrying Fair Carrying Fair 
 Value Value Value Value  Value Value Value Value 
 (In millions)  (In millions) 
 
FirstEnergy (Consolidated) $13,592 $14,920 $13,753 $14,502 
FirstEnergy(1)
 $18,371 $19,436 $13,928 $14,845 
FES 4,181 4,228 4,224 4,306  4,056 4,310 4,279 4,403 
OE 1,159 1,409 1,169 1,299  1,158 1,367 1,159 1,321 
CEI 1,853 2,144 1,873 2,032  1,831 2,083 1,853 2,035 
TE 600 706 600 638  600 690 600 653 
JCP&L 1,819 2,076 1,840 1,950  1,795 2,008 1,810 1,962 
Met-Ed 742 849 842 909  729 828 742 821 
Penelec 1,144 1,269 1,144 1,177  1,120 1,231 1,120 1,189 
(1)Includes debt assumed in the Allegheny merger (See Note 2) with a carrying value and a fair value as of June 30, 2011 of $4,530 million and $4,127 million, respectively.
The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those securitiesobligations based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective period. The yields assumed were based on securitiesdebt with similar characteristics offered by corporations with credit ratings similar to those of FirstEnergy, FES, the Utilities and the Utilities.other subsidiaries.
(B) INVESTMENTS
All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include held-to-maturity securities, available-for-sale securities and notes receivable.
FES and the Utilities periodically evaluate their investments for other-than-temporary impairment. They first consider their intent and ability to hold an equity investment until recovery and then consider, among other factors, the duration and the extent to which the security’s fair value has been less than cost and the near-term financial prospects of the security issuer when evaluating an investment for impairment. For debt securities, FES and the Utilities consider their intent to hold the security, the likelihood that they will be required to sell the security before recovery of their cost basis, and the likelihood of recovery of the security’s entire amortized cost basis.

31

Unrealized gains applicable to the decommissioning trusts of FES, OE and TE are recognized in OCI because fluctuations in fair value will eventually impact earnings while unrealized losses are recorded to earnings. The decommissioning trusts of JCP&L, Met-Ed and Penelec are subject to regulatory accounting. Net unrealized gains and losses are recorded as regulatory assets or liabilities because the difference between investments held in the trust and the decommissioning liabilities will be recovered from or refunded to customers.
The investment policy for the nuclear decommissioning trust funds restricts or limits the trusts’ ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, preferred stocks, securities convertible into common stock and securities of the trust funds’ custodian or managers and their parents or subsidiaries.
Available-For-Sale Securities
FES and the Utilities hold debt and equity securities within their NDT, nuclear fuel disposal trusts and NUG trusts. These trust investments are considered as available-for-sale at fair market value. FES and the Utilities have no securities held for trading purposes.
The following table summarizes the amortized cost basis, unrealized gains and losses and fair values of investments held in nuclear decommissioning trusts,NDT, nuclear fuel disposal trusts and NUG trusts as of SeptemberJune 30, 20102011 and December 31, 2009:2010:
                                                                
 September 30, 2010(1) December 31, 2009(2)  June 30, 2011(1) December 31, 2010(2) 
 Cost Unrealized Unrealized Fair Cost Unrealized Unrealized Fair  Cost Unrealized Unrealized Fair Cost Unrealized Unrealized Fair 
 Basis Gains Losses Value Basis Gains Losses Value  Basis Gains Losses Value Basis Gains Losses Value 
 (In millions)  (In millions) 
Debt securities
  
FirstEnergy $1,795 $73 $— $1,868 $1,727 $22 $— $1,749  $2,015 $48 $— $2,063 $1,699 $31 $— $1,730 
FES 1,079 39 — 1,118 1,043 3 — 1,046  1,023 26 — 1,049 980 13 — 993 
OE 124 4 — 128 55 — — 55  128 3 — 131 123 1 — 124 
TE 31 1 — 32 72 — — 72  52 1 — 53 42 — — 42 
JCP&L 277 15 — 292 271 9 — 280  353 9 — 362 281 9 — 290 
Met-Ed 129 8 — 137 120 5 — 125  249 5 — 254 127 4 — 131 
Penelec 155 6 — 161 166 5 — 171  210 4 — 214 145 4 — 149 
  
Equity securities
  
FirstEnergy $261 $44 $— $305 $252 $43 $— $295  $187 $11 $— $198 $268 $69 $— $337 
FES 90 6 — 96 — — — — 
TE 24 2 — 26 — — — — 
JCP&L 78 9 — 87 74 11 — 85  21 1 — 22 80 17 — 97 
Met-Ed 122 23 — 145 117 23 — 140  32 1 — 33 125 35 — 160 
Penelec 62 10 — 72 61 9 — 70  20 1 — 21 63 16 — 79 
(1) Excludes cash balances:investments, receivables, payables, deferred taxes and accrued income: FirstEnergy — $93– $130 million; FES — $40– $39 million; OE — $2 million; TE — $44– $3 million; JCP&L — $5– $19 million; Met-Ed — $(5)– $14 million and Penelec — $6– $55 million.
 
(2) Excludes cash balances:investments, receivables, payables, deferred taxes and accrued income: FirstEnergy — $137– $193 million; FES — $43– $153 million; OE — $66– $3 million; TE — $2– $34 million; JCP&L —– $3 million; Met-Ed – $(3) million and Penelec — $23– $4 million.

 

2832

Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales net of adjustments recorded to earnings and interest and dividend income for the nine-month periodthree months and six months ended SeptemberJune 30, 20102011 and 20092010 were as follows:
                             
September 30, 2010 FirstEnergy  FES  OE  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
Proceeds from sales $2,577  $1,478  $79  $118  $340  $420  $141 
Realized gains  132   101   2   3   10   10   6 
Realized losses  118   88   —   1   10   12   7 
Interest and dividend income  56   33   2   1   10   5   5 
                 
Three Months Ended June 30, 
 
              Interest and 
2011 Sales Proceeds  Realized Gains  Realized Losses  Dividend Income 
  (In millions) 
FirstEnergy $734  $22  $(16) $28 
FES  297   10   (7)  17 
OE  12   —   —   1 
TE  15   1   (1)  1 
JCP&L  159   4   (2)  4 
Met-Ed  165   4   (3)  3 
Penelec  86   3   (3)  2 
                             
September 30, 2009 FirstEnergy  FES  OE  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
Proceeds from sales $3,040  $2,153  $207  $171  $339  $89  $81 
Realized gains  186   162   11   7��  4   1   1 
Realized losses  96   62   3   —   11   13   7 
Interest and dividend income  47   22   4   2   10   5   4 
                 
              Interest and 
2010 Sales Proceeds  Realized Gains  Realized Losses  Dividend Income 
  (In millions) 
FirstEnergy $1,183  $46  $(36) $16 
FES  685   41   (35)  9 
OE  57   2   —   — 
TE  76   2   —   — 
JCP&L  91   —   —   3 
Met-Ed  233   1   (1)  2 
Penelec  41   —   —   2 
                 
Six Months Ended June 30, 
 
              Interest and 
2011 Sales Proceeds  Realized Gains  Realized Losses  Dividend Income 
  (In millions) 
FirstEnergy $1,703  $122  $(45) $52 
FES  513   22   (23)  32 
OE  20   —   —   2 
TE  28   1   (2)  1 
JCP&L  376   26   (6)  8 
Met-Ed  501   48   (7)  5 
Penelec  265   25   (7)  4 
                 
              Interest and 
2010 Sales Proceeds  Realized Gains  Realized Losses  Dividend Income 
  (In millions) 
FirstEnergy $1,915  $83  $(86) $37 
FES  957   54   (58)  22 
OE  60   2   —   1 
TE  107   3   —   1 
JCP&L  281   9   (9)  7 
Met-Ed  377   9   (12)  3 
Penelec  134   6   (7)  3 
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 SeptemberJune 30, 20102011 and December 31, 2009:2010:
                                                                
 September 30, 2010 December 31, 2009  June 30, 2011 December 31, 2010 
 Cost Unrealized Unrealized Fair Cost Unrealized Unrealized Fair  Cost Unrealized Unrealized Fair Cost Unrealized Unrealized Fair 
 Basis Gains Losses Value Basis Gains Losses Value  Basis Gains Losses Value Basis Gains Losses Value 
 (In millions)  (In millions) 
Debt Securities
  
FirstEnergy $486 $99 $— $585 $544 $72 $— $616  $414 $84 $— 498 $476 $91 $— $567 
OE 205 60 — 265 217 29 — 246  178 45 — 223 190 51 — 241 
CEI 340 31 — 371 389 43 — 432  287 39 — 326 340 41 — 381 
Investments in emission allowances, employee benefits and cost and equity method investments totaling $256$345 million as of SeptemberJune 30, 2010,2011 and $264$259 million as of December 31, 20092010, are not required to be disclosed and are therefore excluded from the amounts reported above.

33

Notes Receivable
The table below provides the approximate fair value and related carrying amounts of notes receivable as of SeptemberJune 30, 20102011 and December 31, 2009.2010. The fair value of notes receivable represents the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms. The maturity dates range from 2013 to 2021.
                                
 September 30, 2010 December 31, 2009  June 30, 2011 December 31, 2010 
 Carrying Fair Carrying Fair  Carrying Fair Carrying Fair 
 Value Value Value Value  Value Value Value Value 
 (In millions)  (In millions) 
Notes Receivable
  
FirstEnergy $7 $8 $36 $35  $6 $7 $7 $8 
FES — — 2 1 
TE 104 114 124 141  82 94 104 118 

34

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 transferAuthoritative accounting guidance establishes a liability (exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between willing market participants on the measurement date. A fair value hierarchy has been established that prioritizes the inputs used to measure fair value. TheThis hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (Level 1)Level 1 measurements and the lowest priority to unobservable inputs (Level 3). Level 3 measurements.
The three levels of the fair value hierarchy are as follows:
Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those where transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. FirstEnergy’s Level 1 assets and liabilities primarily consist of exchange-traded derivatives and equity securities listed on active exchanges that are held in various trusts.

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.
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.
Level 1— Quoted prices for identical instruments in active markets.
Level 2— Quoted prices for similar instruments in active markets;
— quoted prices for identical or similar instruments in markets that are not active; and
— model-derived valuations for which all significant inputs are observable market data.
Level 3— Valuation inputs are unobservable and significant to the fair value measurement.
The following tables set forth financial assets and financial liabilities that are accounted formeasured at fair value on a recurring basis by level within the fair value hierarchy as of Septemberhierarchy. There were no significant transfers between levels during the three months and six months ended June 30, 2010 and December 31, 2009. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. FirstEnergy’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the fair valuation of assets and liabilities and their placement within the fair value hierarchy levels.
                             
  Recurring Fair Value Measures as of September 30, 2010 
  Level 1 
  FirstEnergy  FES  OE  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
Assets
                            
Nuclear Decommissioning Trust Investments — equity securities(1)
 $305  $—  $—  $—  $88  $145  $73 
                      
Total Assets(2)
 $305  $—  $—  $—  $88  $145  $73 
                      
                             
Liabilities
                            
Derivatives — commodity contracts $2  $2  $—  $—  $—  $—  $— 
                      
Total Liabilities
 $2  $2  $—  $—  $—  $—  $— 
                      
2011.

 

3035

                             
  Level 2 
  FirstEnergy  FES  OE  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
Assets
                            
Nuclear Decommissioning Trust Investments
                            
U.S. government debt securities $619  $337  $127  $26  $37  $82  $10 
U.S. state debt securities  88   —   —   —   29   —   59 
Foreign government debt securities  285   285   —   —   —   —   — 
Corporate debt securities  580   496   —   6   23   47   8 
Other  101   38   6   45   2   9   1 
                      
Total Nuclear Decommissioning Trust Investments
 $1,673  $1,156  $133  $77  $91  $138  $78 
                      
                             
Rabbi Trust Investments
                            
Equity securities — financial $1  $—  $—  $—  $—  $—  $— 
Other  11   —   —   —   —   —   — 
                      
Total Rabbi Trust Investments
 $12  $—  $—  $—  $—  $—  $— 
                      
                             
Nuclear Fuel Disposal Trust Investments
                            
U.S. state debt securities $209  $—  $—  $—  $209  $—  $— 
                      
Total Nuclear Fuel Disposal Trust Investments
 $209  $—  $—  $—  $209  $—  $— 
                      
                             
NUG Trust Investments
                            
U.S. state debt securities $86  $—  $—  $—  $—  $—  $86 
Other  6   —   —   —   —   —   6 
                      
Total NUG Trust Investments
 $92  $—  $—  $—  $—  $—  $92 
                      
                             
Derivatives
                            
Commodity contracts $183  $174  $—  $—  $2  $5  $2 
                      
Total Derivatives Contracts
 $183  $174  $—  $—  $2  $5  $2 
                      
Total Assets(2)
 $2,169  $1,330  $133  $77  $302  $143  $172 
                      
                             
Liabilities
                            
Derivatives
                            
Commodity contracts $329  $329  $—  $—  $—  $—  $— 
                      
Total Liabilities
 $329  $329  $—  $—  $—  $—  $— 
                      
FirstEnergy Corp.
                             
  Level 3 
  FirstEnergy  FES  OE  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
Assets
                            
Derivatives — NUG contracts(3)
 $116  $—  $—  $—  $7  $104  $6 
                      
                             
Liabilities
                            
Derivatives — NUG contracts(3)
 $756  $—  $—  $—  $386  $175  $194 
                      
The following tables summarize assets and liabilities recorded on FirstEnergy’s Consolidated Balance Sheets at fair value as of June 30, 2011 and December 31, 2010:
                 
June 30, 2011 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
Corporate debt securities
 $—  $868  $—  $868 
Derivative assets — commodity contracts
  —   312   —   312 
Derivative assets — FTRs
  —   —   13   13 
Derivative assets — interest rate swaps
  —   4   —   4 
Derivative assets — NUG contracts(1)
  —   —   75   75 
Equity securities(2)
  198   —   —   198 
Foreign government debt securities
  —   206   —   206 
U.S. government debt securities
  —   673   —   673 
U.S. state debt securities
  —   306   —   306 
Other(4)
  —   146   —   146 
             
Total assets
 $198  $2,515  $88  $2,801 
             
                 
Liabilities
                
Derivative liabilities — commodity contracts
 $—  $(362) $—  $(362)
Derivative liabilities — FTRs
  —   —   (7)  (7)
Derivative liabilities — interest rate swaps
  —   (5)  —   (5)
Derivative liabilities — NUG contracts(1)
  —   —   (522)  (522)
             
Total liabilities
 $—  $(367) $(529) $(896)
             
 
Net assets (liabilities)(3)
 $198  $2,148  $(441) $1,905 
             
                 
December 31, 2010 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
Corporate debt securities
 $—  $597  $—  $597 
Derivative assets — commodity contracts
  —   250   —   250 
Derivative assets — NUG contracts(1)
  —   —   122   122 
Equity securities(2)
  338   —   —   338 
Foreign government debt securities
  —   149   —   149 
U.S. government debt securities
  —   595   —   595 
U.S. state debt securities
  —   379   —   379 
Other(4)
  —   219   —   219 
             
Total assets
 $338  $2,189  $122  $2,649 
             
                 
Liabilities
                
Derivative liabilities — commodity contracts $—  $(348) $—  $(348)
Derivative liabilities — NUG contracts(1)
  —   —   (466)  (466)
             
Total liabilities
 $—  $(348) $(466) $(814)
             
                 
Net assets (liabilities)(3)
 $338  $1,841  $(344) $1,835 
             
(1)NUG contracts are generally subject to regulatory accounting and do not materially impact earnings.
(2) NDT funds hold equity portfolios whosethe performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.
 
(2)(3) Excludes $(13)$6 million and $(7) million as of June 30, 2011 and December 31, 2010, respectively, of receivables, payables, deferred taxes and accrued income.income associated with the financial instruments reflected within the fair value table.
(4)Primarily consists of cash and cash equivalents.

36

Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the fair value of NUG contracts held by the Utilities and FTRs held by FirstEnergy and classified as Level 3 in the fair value hierarchy during the periods ending June 30, 2011 and December 31, 2010:
             
  Derivative Asset(1)  Derivative Liability(1)  Net(1) 
  (In millions) 
January 1, 2011 Balance $122  $(466) $(344)
Realized gain (loss)  —   —   — 
Unrealized gain (loss)  (40)  (203)  (243)
Purchases  13   (3)  10 
Issuances  —   —   — 
Sales  —   —   — 
Settlements  (6)  154   148 
Transfers into  Level 3  —   (12)  (12)
          
June 30, 2011 Balance $89  $(530) $(441)
          
             
January 1, 2010 Balance $200  $(643) $(443)
Realized gain (loss)  —   —   — 
Unrealized gain (loss)  (71)  (110)  (181)
Purchases  —   —   — 
Issuances  —   —   — 
Sales  —   —   — 
Settlements  (7)  287   280 
Transfers into  Level 3  —   —   — 
          
December 31, 2010 Balance $122  $(466) $(344)
          
(1)Changes in the fair value of NUG contracts are generally subject to regulatory accounting and do not materially impact earnings.

37

FirstEnergy Solutions Corp.
The following tables summarize assets and liabilities recorded on FES’ Consolidated Balance Sheets at fair value as of June 30, 2011 and December 31, 2010:
                 
June 30, 2011 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
Corporate debt securities $—  $562  $—  $562 
Derivative assets — commodity contracts  —   283   —   283 
Derivative assets — FTRs  —   —   2   2 
Equity securities(3)
  96   —   —   96 
Foreign government debt securities  —   160   —   160 
U.S. government debt securities  —   316   —   316 
U.S. state debt securities  —   7   —   7 
Other(2)
  —   42   —   42 
             
Total assets
 $96  $1,370  $2  $1,468 
             
                 
Liabilities
                
Derivative liabilities — commodity contracts $—  $(327) $—  $(327)
             
Total liabilities
 $—  $(327) $—  $(327)
             
                 
Net assets (liabilities)(1)
 $96  $1,043  $2  $1,141 
             
                 
December 31, 2010 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
Corporate debt securities $—  $528  $—  $528 
Derivative assets — commodity contracts  —   241   —   241 
Foreign government debt securities  —   147   —   147 
U.S. government debt securities  —   308   —   308 
U.S. state debt securities  —   6   —   6 
Other(2)
  —   148   —   148 
             
Total assets
 $—  $1,378  $—  $1,378 
             
                 
Liabilities
                
Derivative liabilities — commodity contracts $—  $(348) $—  $(348)
             
Total liabilities
 $—  $(348) $—  $(348)
             
                 
Net assets (liabilities)(1)
 $—  $1,030  $—  $1,030 
             
(1)Excludes $7 million as of December 31, 2010 of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table.
(2)Primarily consists of cash and cash equivalents.
 
(3)NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.
Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the fair value of FTRs held by FES and classified as Level 3 in the fair value hierarchy during the period ending June 30, 2011:
             
  Derivative Asset  Derivative Liability  Net 
  FTRs  FTRs  FTRs 
  (In millions) 
January 1, 2011 Balance $—  $—  $— 
Realized gain (loss)  —   —   — 
Unrealized gain (loss)  1   —   1 
Purchases  2   —   2 
Issuances  —   —   — 
Sales  —   —   — 
Settlements  (1)  —   (1)
Transfers in (out) of Level 3  —   —   — 
          
June 30, 2011 Balance $2  $—  $2 
          

38

Ohio Edison Company
The following tables summarize assets and liabilities recorded on OE’s Consolidated Balance Sheets at fair value as of June 30, 2011 and December 31, 2010:
                 
June 30, 2011 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
U.S. government debt securities $—  $131  $—  $131 
Other  —   2   —   2 
             
Total assets(1)
 $—  $133  $—  $133 
             
                 
December 31, 2010 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
U.S. government debt securities $—  $124  $—  $124 
Other  —   2   —   2 
             
Total assets(1)
 $—  $126  $—  $126 
             
(1)Excludes $2 million and $1 million as of June 30, 2011 and December 31, 2010, respectively, of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table.
The Toledo Edison Company
The following tables summarize assets and liabilities recorded on TE’s Consolidated Balance Sheets at fair value as of June 30, 2011 and December 31, 2010:
                 
June 30, 2011 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
Corporate debt securities $—  $16  $—  $16 
Equity securities(3)
  26   —   —   26 
U.S. government debt securities  —   33   —   33 
U.S. state debt securities  —   1   —   1 
Other(2)
  —   3   —   3 
             
Total assets(1)
 $26  $53  $—  $79 
             
                 
December 31, 2010 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
Corporate debt securities $—  $7  $—  $7 
U.S. government debt securities  —   33   —   33 
U.S. state debt securities  —   1   —   1 
Other(2)
  —   35   —   35 
             
Total assets(1)
 $—  $76  $—  $76 
             
(1)Excludes $(1) million and $2 million as of June 30, 2011 and December 31, 2010, respectively of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table.
(2)Primarily consists of cash and cash equivalents.
(3)NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.

39

Jersey Central Power & Light Company
The following tables summarize assets and liabilities recorded on JCP&L’s Consolidated Balance Sheets at fair value as of June 30, 2011 and December 31, 2010:
                 
June 30, 2011 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
Corporate debt securities $—  $81  $—  $81 
Derivative assets — NUG contracts(1)
  —   —   5   5 
Equity securities(2)
  21   —   —   21 
Foreign government debt securities  —   13   —   13 
U.S. government debt securities  —   54   —   54 
U.S. state debt securities  —   215   —   215 
Other  —   14   —   14 
             
Total assets
 $21  $377  $5  $403 
             
                 
Liabilities
                
Derivative liabilities — NUG contracts(1)
 $—  $—  $(240) $(240)
             
Total liabilities
 $—  $—  $(240) $(240)
             
                 
Net assets (liabilities)(3)
 $21  $377  $(235) $163 
             
                 
December 31, 2010 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
Corporate debt securities $—  $23  $—  $23 
Derivative assets — commodity contracts  —   2   —   2 
Derivative assets — NUG contracts(1)
  —   —   6   6 
Equity securities(2)
  96   —   —   96 
U.S. government debt securities  —   33   —   33 
U.S. state debt securities  —   236   —   236 
Other  —   4   —   4 
             
Total assets
 $96  $298  $6  $400 
             
                 
Liabilities
                
Derivative liabilities — NUG contracts(1)
 $—  $—  $(233) $(233)
             
Total liabilities
 $—  $—  $(233) $(233)
             
                 
Net assets (liabilities)(3)
 $96  $298  $(227) $167 
             
(1) NUG contracts are subject to regulatory accounting and do not impact earnings.
                             
  Recurring Fair Value Measures as of December 31, 2009 
  Level 1 
  FirstEnergy  FES  OE  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
Assets
                            
Nuclear Decommissioning Trust Investments — equity securities(1)
 $294  $—  $—  $—  $87  $133  $74 
                      
Total Assets(2)
 $294  $—  $—  $—  $87  $133  $74 
                      
                             
Liabilities
                            
Derivatives — commodity contracts $11  $11  $—  $—  $—  $—  $— 
                      
Total Liabilities
 $11  $11  $—  $—  $—  $—  $— 
                      

31

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

 

3240

Rollforward of Level 3 Measurements
The following tables set forthtable provides a reconciliation of changes in the fair value of NUG contracts held by JCP&L and classified as Level 3 in the fair value hierarchy forduring the threeperiods ending June 30, 2011 and nine months ended September 30, 2010 and 2009 (in millions):December 31, 2010:
                 
  FirstEnergy  JCP&L  Met-Ed  Penelec 
Balance as of January 1, 2010 $(444) $(391) $33  $(86)
Settlements(1)
  209   99   60   50 
Unrealized losses(1)
  (405)  (88)  (164)  (153)
             
Balance as of September 30, 2010 $(640) $(380) $(71) $(189)
             
                 
Balance as of July 1, 2010 $(557) $(371) $(38) $(148)
Settlements(1)
  63   29   23   11 
Unrealized losses(1)
  (146)  (38)  (56)  (52)
             
Balance as of September 30, 2010 $(640) $(380) $(71) $(189)
             
             
  Derivative Asset  Derivative Liability  Net 
  NUG Contracts(1)  NUG Contracts(1)  NUG Contracts(1) 
  (In millions) 
January 1, 2011 Balance $6  $(233) $(227)
Realized gain (loss)  —   —   — 
Unrealized gain (loss)  (1)  (71)  (72)
Purchases  —   —   — 
Issuances  —   —   — 
Sales  —   —   — 
Settlements  —   64   64 
Transfers in (out) of Level 3  —   —   — 
          
June 30, 2011 Balance $5  $(240) $(235)
          
             
January 1, 2010 Balance $8  $(399) $(391)
Realized gain (loss)  —   —   — 
Unrealized gain (loss)  (1)  36   35 
Purchases  —   —   — 
Issuances  —   —   — 
Sales  —   —   — 
Settlements  (1)  130   129 
Transfers in (out) of Level 3  —   —   — 
          
December 31, 2010 Balance $6  $(233) $(227)
          
                 
  FirstEnergy  JCP&L  Met-Ed  Penelec 
Balance as of January 1, 2009 $(332) $(518) $150  $36 
Settlements(1)
  273   132   63   78 
Unrealized losses(1)
  (406)  (30)  (178)  (198)
             
Balance as of September 30, 2009 $(465) $(416) $35  $(84)
             
                 
Balance as of July 1, 2009 $(536) $(466) $23  $(93)
Settlements(1)
  93   42   20   31 
Unrealized gains (losses)(1)
  (22)  8   (8)  (22)
             
Balance as of September 30, 2009 $(465) $(416) $35  $(84)
             
(1) Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings.

41

Metropolitan Edison Company
The following tables summarize assets and liabilities recorded on Met-Ed’s Consolidated Balance Sheets at fair value as of June 30, 2011 and December 31, 2010:
                 
June 30, 2011 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
Corporate debt securities $—  $138  $—  $138 
Derivative assets — NUG contracts(1)
  —   —   66   66 
Equity securities(2)
  33   —   —   33 
Foreign government debt securities  —   20   —   20 
U.S. government debt securities  —   87   —   87 
U.S. state debt securities  —   2   —   2 
Other  —   22   —   22 
             
Total assets
 $33  $269  $66  $368 
             
                 
Liabilities
                
Derivative liabilities — NUG contracts(1)
 $—  $—  $(122) $(122)
             
Total liabilities
 $—  $—  $(122) $(122)
             
 
Net assets (liabilities)(3)
 $33  $269  $(56) $246 
             
                 
December 31, 2010 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
Corporate debt securities $—  $32  $—  $32 
Derivative assets — commodity contracts  —   5   —   5 
Derivative assets — NUG contracts(1)
  —   —   112   112 
Equity securities(2)
  160   —   —   160 
Foreign government debt securities  —   1   —   1 
U.S. government debt securities  —   88   —   88 
U.S. state debt securities  —   2   —   2 
Other  —   14   —   14 
             
Total assets
 $160  $142  $112  $414 
             
                 
Liabilities
                
Derivative liabilities — NUG contracts(1)
 $—  $—  $(116) $(116)
             
Total liabilities
 $—  $—  $(116) $(116)
             
                 
Net assets (liabilities)(3)
 $160  $142  $(4) $298 
             
(1)NUG contracts are subject to regulatory accounting and do not impact earnings.
(2)NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.
(3)Excludes $(1) million and $(9) million as of June 30, 2011 and December 31, 2010, respectively, of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table.

42

Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the fair value of NUG contracts held by Met-Ed and classified as Level 3 in the fair value hierarchy during the periods ending June 30, 2011 and December 31, 2010:
             
  Derivative Asset  Derivative Liability  Net 
  NUG Contracts(1)  NUG Contracts(1)  NUG Contracts(1) 
  (In millions) 
January 1, 2011 Balance $112  $(116) $(4)
Realized gain (loss)  —   —   — 
Unrealized gain (loss)  (42)  (36)  (78)
Purchases  —   —   — 
Issuances  —   —   — 
Sales  —   —   — 
Settlements  (4)  30   26 
Transfers in (out) of Level 3  —   —   — 
          
June 30, 2011 Balance $66  $(122) $(56)
          
             
January 1, 2010 Balance $176  $(143) $33 
Realized gain (loss)  —   —   — 
Unrealized gain (loss)  (59)  (38)  (97)
Purchases  —   —   — 
Issuances  —   —   — 
Sales  —   —   — 
Settlements  (5)  65   60 
Transfers in (out) of Level 3  —   —   — 
          
December 31, 2010 Balance $112  $(116) $(4)
          
(1)Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings.

43

Pennsylvania Electric Company
The following tables summarize assets and liabilities recorded on Penelec’s Consolidated Balance Sheets at fair value as of June 30, 2011 and December 31, 2010:
                 
June 30, 2011 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
Corporate debt securities $—  $69  $—  $69 
Derivative assets — NUG contracts(1)
  —   —   4   4 
Equity securities(2)
  20   —   —   20 
Foreign government debt securities      12       12 
U.S. government debt securities  —   52   —   52 
U.S. state debt securities  —   81   —   81 
Other  —   53   —   53 
             
Total assets
 $20  $267  $4  $291 
             
                 
Liabilities
                
Derivative liabilities — NUG contracts(1)
 $—  $—  $(160) $(160)
             
Total liabilities
 $—  $—  $(160) $(160)
             
                 
Net assets (liabilities)(3)
 $20  $267  $(156) $131 
             
                 
December 31, 2010 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
Corporate debt securities $—  $8  $—  $8 
Derivative assets — commodity contracts  —   2   —   2 
Derivative assets — NUG contracts(1)
  —   —   4   4 
Equity securities(2)
  81   —   —   81 
U.S. government debt securities  —   9   —   9 
U.S. state debt securities  —   133   —   133 
Other  —   5   —   5 
             
Total assets
 $81  $157  $4  $242 
             
                 
Liabilities
                
Derivative liabilities — NUG contracts(1)
 $—  $—  $(117) $(117)
             
Total liabilities
 $—  $—  $(117) $(117)
             
                 
Net assets (liabilities)(3)
 $81  $157  $(113) $125 
             
(1)NUG contracts are subject to regulatory accounting and do not impact earnings.
(2)NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.
(3)Excludes $1 million and $(3) million as of June 30, 2011 and December 31, 2010, respectively, of receivables, payables and accrued income associated with the financial instruments reflected within the fair value table.

44

Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the fair value of NUG and commodity contracts held by Penelec and classified as Level 3 in the fair value hierarchy during the periods ended June 30, 2011 and December 31, 2010:
             
  Derivative Asset  Derivative Liability  Net 
  NUG Contracts(1)  NUG Contracts(1)  NUG Contracts(1) 
  (In millions) 
January 1, 2011 Balance $4  $(117) $(113)
Realized gain (loss)  —   —   — 
Unrealized gain (loss)  —   (88)  (88)
Purchases  —   —   — 
Issuances  —   —   — 
Sales  —   —   — 
Settlements  —   45   45 
Transfers in (out) of Level 3  —   —   — 
          
June 30, 2011 Balance $4  $(160) $(156)
          
             
January 1, 2010 Balance $16  $(101) $(85)
Realized gain (loss)  —   —   — 
Unrealized gain (loss)  (11)  (108)  (119)
Purchases  —   —   — 
Issuances  —   —   — 
Sales  —   —   — 
Settlements  (1)  92   91 
Transfers in (out) of Level 3  —   —   — 
          
December 31, 2010 Balance $4  $(117) $(113)
          
(1)Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings.
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.practice. FirstEnergy also uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps. In addition to derivatives, FirstEnergy also enters into master netting agreements with certain third parties.
FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value unless they meet the normal purchases and normal sales criteria. Derivatives that meet those criteria are accounted for at cost under the accrual method of accounting. The changesaccounting, and their effects are included in earnings at the time of contract performance. Changes in the fair value of derivative instruments that do not meetqualify and are designated as cash flow hedge instruments are recorded in AOCL. Changes in the normal purchases and normal sales criteria are included in purchased power, other expense, unrealized gain (loss) on derivative hedges in other comprehensive income (loss), or as part of thefair value of the hedged item. Based on derivative contracts heldinstruments that are not designated as of September 30, 2010, an adverse 10% changecash flow hedge instruments are recorded in commodity prices would decrease net income by approximately $6 million ($4 million net of tax) during the next twelve months. A hypothetical 10% increase in the interest rates associated with variable-rate debt would decrease net income by approximately $1 million for the three and nine months ended September 30, 2010.on a mark-to-market basis. FirstEnergy has contractual derivative agreements through December 2018.
Cash Flow Hedges
FirstEnergy has used cash flow hedges for risk management purposes to manage the volatility related to exposures associated with fluctuating interest rates and commodity prices. The effective portion of gains and losses on the derivative contract are reported as a component of AOCL with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects earnings.
As of December 31, 2010, commodity derivative contracts designated in cash flow hedging relationships were $104 million of assets and $101 million of liabilities. In February 2011, FirstEnergy elected to dedesignate all outstanding cash flow hedge relationships. Total net unamortized gains included in AOCL associated with dedesignated cash flow hedges totaled $8 million as of June 30, 2011. Since the forecasted transactions remain probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments. Reclassifications from AOCL into other operating expenses totaled $14 million and $19 million during the three months and six months ended June 30, 2011, respectively. Approximately $3 million is expected to be amortized to expense during the next twelve months.
FirstEnergy has used forward starting swap agreements to hedge a portion of the consolidated interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives were treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. As of SeptemberJune 30, 2010,2011, no forward starting swap agreements were outstanding.
Total unamortized losses included in AOCL associated with prior interest rate cash flow hedges totaled $95$84 million ($6255 million net of tax) as of SeptemberJune 30, 2010.2011. Based on current estimates, approximately $11$10 million will be amortized to interest expense during the next twelve months. The table below providesReclassifications from AOCL into interest expense totaled $3 million during the activity of AOCL related to interest rate cash flow hedges as of Septemberthree months ended June 30, 2011 and 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)
$6 million during the six months ended June 30, 2011 and 2010.

 

3345

Fair Value Hedges
FirstEnergy has used fixed-for-floating interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with the debt portfolio of its subsidiaries. These derivativesderivative instruments were treated as fair value hedges of fixed-rate, long-term debt issues, protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. As of SeptemberJune 30, 2010,2011, no fixed-for-floating interest rate swap agreements were outstanding.
Total unamortizedUnamortized gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements totaled $129$113 million ($8473 million net of tax) as of SeptemberJune 30, 2010.2011. Based on current estimates, approximately $22 million will be amortized to interest expense during the next twelve months. Reclassifications from long-term debt into interest expense totaled $5approximately $6 million and $7$2 million forduring the three and nine months ended SeptemberJune 30, 2010.2011 and 2010, respectively and $11 million and $3 million during the six months ended June 30, 2011 and 2010, respectively.
Commodity Derivatives
FirstEnergy uses both physically and financially settled derivatives to manage its exposure to volatility in commodity prices. Commodity derivatives are used for risk management purposes to hedge exposures when it makes economic sense to do so, including circumstances where the hedging relationship does not qualify for hedge accounting.
The following tables summarize the fair value of commodity derivatives in FirstEnergy’s Consolidated Balance Sheets:
                   
Cash Flow Hedges 
Derivative Assets  Derivative Liabilities 
  Fair Value    Fair Value 
  September 30,  December 31,    September 30,  December 31, 
  2010  2009    2010  2009 
  (In millions)    (In millions) 
    
Electricity Forwards         Electricity Forwards        
Current Assets $77  $3  Current Liabilities $87  $7 
NonCurrent Assets  73   11  NonCurrent Liabilities  70   12 
Natural Gas Futures         Natural Gas Futures        
Current Assets  —   —  Current Liabilities  1   9 
NonCurrent Assets  —   —  NonCurrent Liabilities  —   — 
Other         Other        
Current Assets  —   —  Current Liabilities  —   2 
NonCurrent Assets  —   —  NonCurrent Liabilities  —   — 
               
  $150  $14    $158  $30 
               
                   
Economic Hedges 
Derivative Assets  Derivative Liabilities 
  Fair Value    Fair Value 
  September 30,  December 31,    September 30,  December 31, 
  2010  2009    2010  2009 
  (In millions)    (In millions) 
                   
NUG Contracts         NUG Contracts        
Power Purchase         Power Purchase        
Contract Asset $116  $200  Contract Liability $756  $643 
Other         Other        
Current Assets  17   —  Current Liabilities  138   106 
NonCurrent Assets  15   19  NonCurrent Liabilities  34   97 
               
   148   219     928   846 
               
Total Commodity Derivatives $298  $233  Total Commodity Derivatives $1,086  $876 
               
Electricity forwards are used to balance expected sales with expected generation and purchased power. Natural gas futures are entered into based on expected consumption of natural gas; primarily natural gas primarilyis used in FirstEnergy’s peaking units. Heating oil futures are entered into based on expected consumption of oil and the financial risk in FirstEnergy’s coal transportation contracts. Interest rate swaps include two interest rate swap agreements that expire during 2011 with an aggregate notional value of $200 million that were entered into during 2003 to substantially offset two existing interest rate swaps with the same counterparty. The 2003 agreements effectively locked in a net liability and substantially eliminated future income volatility from the interest rate swap positions but do not qualify for cash flow hedge accounting. Derivative instruments are not used in quantities greater than forecasted needs.
As of June 30, 2011, FirstEnergy’s net liability position under commodity derivative contracts was $45 million, which primarily related to FES positions. Under these commodity derivative contracts, FES posted $81 million and Allegheny posted $2 million in collateral. Certain commodity derivative contracts include credit risk related contingent features that would require FES to post $49 million of additional collateral if the credit rating for its debt were to fall below investment grade.
Based on derivative contracts held as of June 30, 2011, an adverse 10% change in commodity prices would decrease net income by approximately $31 million ($20 million net of tax) during the next twelve months.
FTRs
FirstEnergy holds FTRs that generally represent an economic hedge of future congestion charges that will be incurred in connection with FirstEnergy’s load obligations. FirstEnergy acquires the majority of its FTRs in an annual auction through a self-scheduling process involving the use of ARRs allocated to members of an RTO that have load serving obligations and through the direct allocation of FTRs from the PJM RTO. The PJM RTO has a rule that allows directly allocated FTRs to be granted to LSEs in zones that have newly entered PJM. For the first two planning years, PJM permits the LSEs to request a direct allocation of FTRs in these new zones at no cost as opposed to receiving ARRs. The directly allocated FTRs differ from traditional FTRs in that the ownership of all or part of the FTRs may shift to another LSE if customers choose to shop with the other LSE.
The future obligations for the FTRs acquired at auction are reflected on the Consolidated Balance Sheets and have not been designated as cash flow hedge instruments. FirstEnergy initially records these FTRs at the auction price less the obligation due to the RTO, and subsequently adjusts the carrying value of remaining FTRs to their estimated fair value at the end of each accounting period prior to settlement. Changes in the fair value of FTRs held by FirstEnergy’s unregulated subsidiaries are included in other operating expenses as unrealized gains or losses. Unrealized gains or losses on FTRs held by FirstEnergy’s regulated subsidiaries are recorded as regulatory assets or liabilities. Directly allocated FTRs are accounted for under the accrual method of accounting, and their effects are included in earnings at the time of contract performance.

46

The following tables summarize the fair value of derivative instruments in FirstEnergy’s Consolidated Balance Sheets:
Derivatives not designated as hedging instruments as of June 30, 2011:
         
Derivative Assets 
 
  Fair Value 
  June 30,  December 31, 
  2011  2010 
  (In millions) 
         
Power Contracts        
Current Assets $210  $96 
Noncurrent Assets  102   40 
FTRs        
Current Assets  13   — 
Noncurrent Assets  —   — 
NUGs        
Current Assets  4   3 
Noncurrent Assets  71   119 
Interest Rate Swaps        
Current Assets  4   — 
Noncurrent Assets  —   — 
Other        
Current Assets  —   10 
Noncurrent Assets  —   — 
       
Total Derivatives $404  $268 
       
         
Derivative Liabilities 
 
  Fair Value 
  June 30,  December 31, 
  2011  2010 
  (In millions) 
         
Power Contracts        
Current Liabilities $274  $209 
Noncurrent Liabilities  88   38 
FTRs        
Current Liabilities  7   — 
Noncurrent Liabilities  —   — 
NUGs        
Current Liabilities  317   229 
Noncurrent Liabilities  205   238 
Interest Rate Swaps        
Current Liabilities  5   — 
Noncurrent Liabilities  —   — 
Other        
Current Liabilities  —   — 
Noncurrent Liabilities  —   — 
       
Total Derivatives $896  $714 
       
The following table summarizes the volume ofvolumes associated with FirstEnergy’s outstanding derivative transactions as of SeptemberJune 30, 2010:2011:
                 
  Purchases  Sales  Net  Units 
  (In thousands) 
Electricity Forwards  28,456   (32,604)  (4,148) MWH
Heating Oil Futures  840   —   840  Gallons
Natural Gas Futures  500   (500)  —  mmBtu
               
  Purchases  Sales  Net  Units
  (In thousands)
Power Contracts  45,573   (59,549)  (13,976) MWH
FTRs  53,656   —   53,656  MWH
Interest Rate Swaps  200,000   (200,000)  —  notional dollars
NUGs  26,903   —   26,903  MWH

 

3447

The effect of derivative instruments on the consolidated statementsConsolidated Statements of income and comprehensive income forIncome during the three months and ninesix months ended SeptemberJune 30, 20102011 and 2009,2010, are summarized in the following tables:
                           
 Three Months Ended September 30,  Three Months Ended June 30, 
 Electricity Natural Gas Heating Oil    Power Interest     
Derivatives in Cash Flow Hedging Relationships Forwards Futures Futures Total 
 Contracts FTRs Rate Swaps Other Total 
 (In millions) 
Derivatives in a Hedging Relationship
 
2011
 
Gain (Loss) Recognized in AOCL (Effective Portion) $14 $— $— $— $14 
Effective Gain (Loss) Reclassified to:(1)
 
Purchase Power Expense — — — — — 
Revenues — — — — — 
 (In millions)  
2010
  
Gain (Loss) Recognized in AOCL (Effective Portion) $(2) $— $— $(2) $— $— $— $3 $3 
Effective Gain (Loss) Reclassified to:(1)
  
Purchased Power Expense  (1) — —  (1)
Purchase Power Expense  (3) — — —  (3)
Revenues  (5) — — —  (5)
Fuel Expense —  (3)  (1)  (4) — — —  (4)  (4)
 
2009
 
Gain (Loss) Recognized in AOCL (Effective Portion) $15 $(2) $— $13 
Effective Gain (Loss) Reclassified to:(1)
 
Purchased Power Expense 11 — — 11 
Fuel Expense —  (4)  (2)  (6)
                 
  Nine Months Ended September 30, 
  Electricity  Natural Gas  Heating Oil    
Derivatives in Cash Flow Hedging Relationships Forwards  Futures  Futures  Total 
  (In millions) 
2010
                
Gain (Loss) Recognized in AOCL (Effective Portion) $(15) $(1) $—  $(16)
Effective Gain (Loss) Reclassified to:(1)
                
Purchased Power Expense  (12)  —   —   (12)
Fuel Expense  —   (9)  (2)  (11)
                 
2009
                
Gain (Loss) Recognized in AOCL (Effective Portion) $19  $(9) $—  $10 
Effective Gain (Loss) Reclassified to:(1)
                
Purchased Power Expense  (6)  —   —   (6)
Fuel Expense  —   (9)  (10)  (19)
                     
                     
Derivatives Not in a Hedging Relationship
                    
2011
                    
Unrealized Gain (Loss) Recognized in:                    
Purchase Power Expense $33  $—  $—  $—  $33 
Revenues  (4)  —   —   —   (4)
Other Operating Expense  (34)  13   —   —   (21)
                     
Realized Gain (Loss) Reclassified to:                    
Purchase Power Expense  1   —   —   —   1 
Revenues  (39)  18   —   —   (21)
Other Operating Expense  —   (59)  —   —   (59)
                     
2010
                    
Unrealized Gain (Loss) Recognized in:                    
Purchase Power Expense $66  $—  $—  $—  $66 
                     
Realized Gain (Loss) Reclassified to:                    
Purchase Power Expense  (26)  —   —   —   (26)
             
Derivatives Not in a Hedging Three Months Ended June 30, 
Relationship with Regulatory Offset(2) NUGs  Other  Total 
  (In millions) 
2011
            
Unrealized Gain (Loss) to Derivative Instrument: $(147) $2  $(145)
Unrealized Gain (Loss) to Regulatory Assets:  147   (2)  145 
 
Realized Gain (Loss) to Derivative Instrument:  62   —   62 
Realized Gain (Loss) to Regulatory Assets:  (62)  —   (62)
 
2010
            
Unrealized Gain (Loss) to Derivative Instrument: $(35)  —  $(35)
Unrealized Gain (Loss) to Regulatory Assets:  35   —   35 
 
Realized Gain (Loss) to Derivative Instrument:  68   —   68 
Realized Gain (Loss) to Regulatory Assets:  (68)  —   (68)

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  Six Months Ended June 30, 
  Power      Interest       
  Contracts  FTRs  Rate Swaps  Other  Total 
  (In millions) 
Derivatives in a Hedging Relationship
                    
2011
                    
Gain (Loss) Recognized in AOCL (Effective Portion) $5  $—  $—  $—  $5 
Effective Gain (Loss) Reclassified to:(1)
                    
Purchase Power Expense  16   —   —   —   16 
Revenues  (12)  —   —   —   (12)
                     
2010
                    
Gain (Loss) Recognized in AOCL (Effective Portion) $(2) $—  $—  $6  $4 
Effective Gain (Loss) Reclassified to:(1)
                    
Purchase Power Expense  (7)  —   —   —   (7)
Revenues  (5)  —   —   —   (5)
Fuel Expense  —   —   —   (8)  (8)
                     
Derivatives Not in a Hedging Relationship
                    
2011
                    
Unrealized Gain (Loss) Recognized in:                    
Purchase Power Expense $61  $—  $—  $—  $61 
Revenues  (3)  —   —   —   (3)
Other Operating Expense  (54)  13   1   —   (40)
                     
Realized Gain (Loss) Reclassified to:                    
Purchase Power Expense  (36)  —   —   —   (36)
Revenues  (29)  26   —   —   (3)
Other Operating Expense  —   (87)  —   —   (87)
                     
2010
                    
Unrealized Gain (Loss) Recognized in:                    
Purchase Power Expense $39  $—  $—  $—  $39 
                     
Realized Gain (Loss) Reclassified to:                    
Purchase Power Expense  (49)  —   —   —   (49)
             
Derivatives Not in a Hedging Six Months Ended June 30, 
Relationship with Regulatory Offset(2) NUGs  Other  Total 
  (In millions) 
2011
            
Unrealized Gain (Loss) to Derivative Instrument: $(236) $2  $(234)
Unrealized Gain (Loss) to Regulatory Assets:  236   (2)  234 
             
Realized Gain (Loss) to Derivative Instrument:  134   (10)  124 
Realized Gain (Loss) to Regulatory Assets:  (134)  10   (124)
             
2010
            
Unrealized Gain (Loss) to Derivative Instrument: $(259)  —  $(259)
Unrealized Gain (Loss) to Regulatory Assets:  259   —   259 
             
Realized Gain (Loss) to Derivative Instrument:  146   (9)  137 
Realized Gain (Loss) to Regulatory Assets:  (146)  9   (137)
(1) The ineffective portion was immaterial.
             
  Three Months Ended September 30, 
  NUG       
Derivatives Not in Hedging Relationships Contracts  Other  Total 
  (In millions) 
2010
            
Unrealized Gain (Loss) Recognized in:            
Purchased Power Expense $—  $(13) $(13)
Regulatory Assets (2)
  (145)  —   (145)
          
  $(145) $(13) $(158)
          
             
Realized Gain (Loss) Reclassified to:            
Purchased Power Expense $—  $(30) $(30)
Regulatory Assets (2)
  (63)  —   (63)
          
  $(63) $(30) $(93)
          
             
2009
            
Unrealized Gain (Loss) Recognized in:            
Fuel Expense (1)
 $—  $(1) $(1)
Regulatory Assets (2)
  (22)  —   (22)
          
  $(22) $(1) $(23)
          
             
Realized Gain (Loss) Reclassified to:            
Fuel Expense (1)
 $—  $1  $1 
Regulatory Assets (2)
  (93)  —   (93)
          
  $(93) $1  $(92)
          

35

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

 

3649

The following table provides a reconciliation of changes in the fair value of certain contracts that are deferred for future recovery from (or refund to) customers during the three months and six months ended June 30, 2011 and 2010:
             
  Three Months Ended June 30, 
Derivatives Not in a Hedging Relationship with Regulatory Offset(1) NUGs  Other  Total 
  (In millions) 
Outstanding net asset (liability) as of April 1, 2011 $(362) $—  $(362)
Additions/Change in value of existing contracts  (147)  2   (145)
Settled contracts  62   —   62 
          
Outstanding net asset (liability) as of June 30, 2011 $(447) $2  $(445)
          
             
Outstanding net asset (liability) as of April 1, 2010 $(590) $10  $(580)
Additions/Change in value of existing contracts  (35)  —   (35)
Settled contracts  68   —   68 
          
Outstanding net asset (liability) as of June 30, 2010 $(557) $10  $(547)
          
             
  Six Months Ended June 30, 
Derivatives Not in a Hedging Relationship with Regulatory Offset(1) NUGs  Other  Total 
  (In millions) 
Outstanding net asset (liability) as of January 1, 2011 $(345) $10  $(335)
Additions/Change in value of existing contracts  (236)  2   (234)
Settled contracts  134   (10)  124 
          
Outstanding net asset (liability) as of June 30, 2011 $(447) $2  $(445)
          
             
Outstanding net asset (liability) as of January 1, 2010 $(444) $19  $(425)
Additions/Change in value of existing contracts  (259)  —   (259)
Settled contracts  146   (9)  137 
          
Outstanding net asset (liability) as of June 30, 2010 $(557) $10  $(547)
          
(1)Changes in the fair value of certain contracts are deferred for future recovery from (or refund to) customers.
6. PENSION AND OTHER POSTRETIREMENT BENEFITS
FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and compensation levels.
FirstEnergy provides a portion of non-contributory pre-retirement basic life insurance for employees who are eligible to retire. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.
FirstEnergy’s netfunding policy is based on actuarial computations using the projected unit credit method. During the three months and six months ended June 30, 2011, FirstEnergy made pre-tax contributions to its qualified pension plans of $105 million and $262 million, respectively. FirstEnergy intends to make additional contributions of $116 million and $2 million to its qualified pension plans and postretirement benefit plans, respectively, in the last two quarters of 2011.

50

As result of the merger with Allegheny, FirstEnergy assumed certain pension and OPEB expenseplans. FirstEnergy measured the funded status of the Allegheny pension plans and postretirement benefit plans other than pensions as of the merger closing date using discount rates of 5.50% and 5.25%, respectively. The fair values of plan assets for Allegheny’s pension plans and postretirement benefit plans other than pensions at the three months ended September 30, 2010 and 2009 was $20date of the merger were $954 million and $36$75 million, respectively, and the actuarially determined benefit obligations for such plans as of that date were $1,341 million and $272 million, respectively. FirstEnergy’sThe expected returns on plan assets used to calculate net periodic costs for periods in 2011 subsequent to the date of the merger are 8.25% for Allegheny’s qualified pension plan and 5.00% for Allegheny’s postretirement benefit plans other than pensions.
The components of the consolidated net periodic cost for pension and OPEB expense for the nine months ended September 30, 2010 and 2009 was $65 million and $117 million, respectively. The components of FirstEnergy’s net pension and other postretirement benefit costsbenefits (including amounts capitalized) for the three and nine months ended September 30, 2010 and 2009, consisted of the following:were as follows:
                                
 Three Months Ended Nine Months Ended  Three Months Ended Six Months Ended 
 September September 30  June 30 June 30 
Pension Benefit Cost (Credit) 2010 2009 2010 2009  2011 2010 2011 2010 
 (In millions)  (In millions) 
Service cost $25 $23 $74 $66  $34 $25 $62 $49 
Interest cost 79 79 236 239  97 79 181 157 
Expected return on plan assets  (90)  (86)  (271)  (248)  (115)  (90)  (216)  (181)
Amortization of prior service cost 3 3 10 10  4 3 7 6 
Recognized net actuarial loss 47 45 141 129  48 47 97 94 
Curtailments(1)
 — —  (2) — 
Special termination benefits(1)
 — — 9 — 
                  
Net periodic cost $64 $64 $190 $196  $68 $64 $138 $125 
                  
(1)Represents costs (credits) incurred related to change in control provision payments to certain executives who were terminated or were expected to be terminated as a result of the merger.
                                
 Three Months Ended Nine Months Ended  Three Months Ended Six Months Ended 
 September 30 September 30  June 30 June 30 
Other Postretirement Benefit Cost (Credit) 2010 2009 2010 2009  2011 2010 2011 2010 
 (In millions)  (In millions) 
Service cost $2 $15 $7 $23  $3 $3 $7 $5 
Interest cost 11 13 33 51  12 11 23 22 
Expected return on plan assets  (9)  (9)  (27)  (27)  (10)  (9)  (20)  (18)
Amortization of prior service cost  (48)  (48)  (144)  (127)  (52)  (48)  (100)  (96)
Recognized net actuarial loss 15 15 45 46  14 15 28 30 
                  
Net periodic cost $(29) $(14) $(86) $(34)
Net periodic cost (credit) $(33) $(28) $(62) $(57)
                  
Pension and other postretirement benefitOPEB obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. The net periodic pension costs and net periodic other postretirement benefit costsOPEB (including amounts capitalized) recognized by FirstEnergy’s subsidiaries for the three and nine months ended September 30, 2010 and 2009 were as follows:
                                
 Three Months Ended Nine Months Ended  Three Months Ended Six Months Ended 
 September 30 September 30  June 30 June 30 
Pension Benefit Cost 2010 2009 2010 2009  2011 2010 2011 2010 
 (In millions)  (In millions) 
FES $22 $19 $66 $56  $22 $22 $43 $44 
OE 6 6 17 20  5 6 11 11 
CEI 5 5 16 14  5 5 10 11 
TE 2 2 5 5  2 2 3 4 
JCP&L 6 8 19 26  5 6 11 12 
Met-Ed 3 5 8 16  3 3 5 5 
Penelec 5 4 14 13  4 5 9 9 
Other FirstEnergy Subsidiaries 15 15 45 46  22 15 46 29 
                  
 $64 $64 $190 $196  $68 $64 $138 $125 
                  

 

3751

                                
 Three Months Ended Nine Months Ended  Three Months Ended Six Months Ended 
 September 30 September 30  June 30 June 30 
Other Postretirement Benefit Cost (Credit) 2010 2009 2010 2009 
Other Postretirement Benefit Credit 2011 2010 2011 2010 
 (In millions)  (In millions) 
FES $(7) $(4) $(20) $(8) $(8) $(7) $(14) $(13)
OE  (6)  (3)  (19)  (8)  (5)  (6)  (12)  (12)
CEI  (1) —  (4) 1   (2)  (1)  (3)  (3)
TE — 1  (1) 2  — —  (1)  (1)
JCP&L  (2)  (2)  (5)  (4)  (2)  (2)  (3)  (4)
Met-Ed  (2)  (1)  (6)  (3)  (2)  (2)  (5)  (4)
Penelec  (2)  (1)  (6)  (2)  (2)  (2)  (5)  (4)
Other FirstEnergy Subsidiaries  (9)  (4)  (25)  (12)  (12)  (8)  (19)  (16)
                  
 $(29) $(14) $(86) $(34) $(33) $(28) $(62) $(57)
                  
7. VARIABLE INTEREST ENTITIES
FirstEnergy’s consolidated financial statements include the accounts of entities in which it has a controlling financial interest. FirstEnergy consolidates certain VIEs in which it has financial control through disproportionate economics in its equity and debt investments in the entities. These VIEs include: FEV’s joint venture in the Signal Peak mining and coal transportation operations; the PNBV and Shippingport bond trusts that were created to refinance debt originally issued in connection with sale and leaseback transactions; and wholly owned limited liability companies of JCP&L created to sell transition bonds to securitize the recovery of JCP&L’s bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station, of which $319 million was outstanding as of September 30, 2010.
FirstEnergy and its subsidiaries reflect the portion of VIEs not owned by them in the caption noncontrolling interest within the consolidated financial statements. The change in noncontrolling interest within the consolidated balance sheets is the result of net losses of the noncontrolling interests ($19 million) and distributions to owners ($5 million) for the nine months ended September 30, 2010.
On January 1, 2010, FirstEnergy adopted the amendments to the consolidation topic addressing VIEs. This standard requires that FirstEnergy and its subsidiaries perform a qualitative analysisanalyses to determine whether a variable interest gives FirstEnergy or its subsidiaries a controlling financial interest in a VIE. This analysis identifies the primary beneficiary of a VIE as the enterprise that has both the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. This standard also requires an ongoing reassessment
VIEs included in FirstEnergy’s consolidated financial statements are: FEV’s joint venture in the Signal Peak mining and coal transportation operations; the PNBV and Shippingport bond trusts that were created to refinance debt originally issued in connection with sale and leaseback transactions; and wholly owned limited liability companies of JCP&L created to sell transition bonds to securitize the recovery of JCP&L’s bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station, of which $295 million was outstanding as of June 30, 2011.
FirstEnergy and its subsidiaries reflect the portion of VIEs not owned by them in the caption noncontrolling interest within the consolidated financial statements. The change in noncontrolling interest within the Consolidated Balance Sheets is primarily the result of net losses of the primary beneficiary of a VIEnoncontrolling interests ($15 million) and eliminatesdistributions to owners ($4 million) during 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.six months ended June 30, 2011.
In order to evaluate contracts under thefor consolidation guidance,treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregated contractsvariable interests into twothe following categories based on similar risk characteristics and significancesignificance.
PATH-WV
PATH, LLC was formed to construct, through its operating companies, the PATH Project, which is a high-voltage transmission line that was proposed to extend from West Virginia through Virginia and into Maryland, including modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland as follows:directed by PJM. PATH, LLC is a series limited liability company that is comprised of multiple series, each of which has separate rights, powers and duties regarding specified property and the series profits and losses associated with such property. A subsidiary of AE owns 100% of the Allegheny Series and 50% of the West Virginia Series (PATH-WV), which is a joint venture with a subsidiary of AEP. FirstEnergy is not the primary beneficiary of PATH-WV, as it does not have control over the significant activities affecting the economics of the portion of the PATH Project to be constructed by PATH-WV.
Because of the nature of PATH-WV’s operations and its FERC approved rate mechanism, FirstEnergy’s maximum exposure to loss, through AE, consists of its equity investment in PATH-WV, which was $27 million at June 30, 2011.
Power Purchase Agreements
FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities may be VIEs to the extent that they own a plant that sells substantially all of its output to the Utilities andif the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed, Penelec, PE, WP and Penelec,MP, maintains 2123 long-term power purchase agreements with NUG entities. The agreementsentities that were entered into pursuant to the Public Utility Regulatory Policies Act of 1978.PURPA. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, these entities.
FirstEnergy has determined that for all but twofour of these NUG entities, neither JCP&L, nor Met-Ed nor Penelecits subsidiaries do not have variable interests in the entities or the entities are governmental or not-for-profit organizations that aredo not withinmeet the scope of consolidation consideration for VIEs.criteria to be considered a VIE. JCP&L, PE and WP may hold variable interests in the remaining two entities, which sell their output at variable prices that correlate to some extent with the operating costs of the plants. However,four entities; however, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities.

52

Since
Because JCP&L, hasPE and WP have no equity or debt interests in the NUG entities, itstheir maximum exposure to loss relates primarily to the above-market costs it incursincurred for power. FirstEnergy expects any above-market costs it incursincurred by its subsidiaries to be recovered from customers.customers, except as described further below. Purchased power costs related to the four contracts that may contain a variable interest that were held by FirstEnergy subsidiaries during the three months ended June 30, 2011, were $55 million, $47 million and $21 million for JCP&L, PE and WP, respectively and $120 million, $58 million and $26 million for the six months ended June 30, 2011, respectively. Purchased power costs related to the two contracts that may contain a variable interest that were $73 million and $58 million forheld by JCP&L during the three months and six months ended SeptemberJune 30, 2010 and 2009, respectively and $190were $53 million and $173$117 million, respectively.
In 1998 the PPUC issued an order approving a transition plan for WP that disallowed certain costs, including an estimated amount for an adverse power purchase commitment related to the nine months ended SeptemberNUG entity that WP may hold a variable interest, for which WP has taken the scope exception. As of June 30, 20102011, WP’s reserve for this adverse purchase power commitment was $59 million, including a current liability of $11 million, and 2009, respectively.is being amortized over the life of the commitment.

38

Loss Contingencies
FirstEnergy has variable interests in certain sale-leasebacksale and leaseback transactions. FirstEnergy is not the primary beneficiary of these interests as it does not have control over the significant activities affecting the economics of the arrangement.
FES and the Ohio Companies are exposed to losses under their applicable sale-leasebacksale and leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur.events. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty events that render the applicable plant worthless.events. Net discounted lease payments would not be payable if the casualty loss payments were made. The following table discloses each company’s net exposure to loss based upon the casualty value provisions mentioned above as of SeptemberJune 30, 2010:2011:
                        
 Maximum Discounted Lease Net  Maximum Discounted Lease Net 
 Exposure Payments, net(1) Exposure  Exposure Payments, net(1) Exposure 
 (In millions)  (In millions) 
FES $1,376 $1,185 $191  $1,348 $1,156 $192 
OE 672 511 161  635 445 190 
CEI(2)
 627 71 556  624 69 555 
TE(2)
 627 346 281  624 303 321 
(1) The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is $1.7$1.6 billion.
 
(2) CEI and TE are jointly and severally liable for the maximum loss amounts under certain sale-leaseback agreements.
8. INCOME TAXES
FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. Accounting guidance prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of tax positions taken or expected to be taken on a company’s tax return. After reachingAs a settlement at appealsresult of the merger with Allegheny in the first quarter of 2011, FirstEnergy’s unrecognized tax benefits increased by $97 million. During the second quarter of 2010 related primarily to the capitalization of certain costs for the tax years 2005-2008 and2011, FirstEnergy reached a settlement inwith the third quarter of 2010 of an unrelated federal tax matter related to prior year gainsIRS on a research and losses recognized from the disposition of assets, FirstEnergydevelopment claim and recognized approximately $78$30 million of netincome tax benefits, including $21$5 million that favorably affected FirstEnergy’s effective tax rate for the second quarter and first ninesix months of 2011. There were no other material changes to FirstEnergy’s unrecognized income tax benefits during the first six months of 2011. After reaching a tentative agreement with the IRS on a tax item at appeals related to the capitalization of certain costs for tax years 2005-2008, as well as reaching a settlement on an unrelated state tax matter in the second quarter of 2010, FirstEnergy recognized approximately $70 million of net income tax benefits, including $13 million that favorably affected FirstEnergy’s effective tax rate for the second quarter of 2010. The remaining portion of the income tax benefit recognized in the first six months of 2010 increased FirstEnergy’s accumulated deferred income taxes. Upon completion of the federal tax examinationtaxes for the 2007settled temporary tax year in the first quarter of 2009, FirstEnergy recognized $13 million in tax benefits, which favorably affected FirstEnergy’s effective tax rate. There were no material changes to FirstEnergy’s unrecognized tax benefits in the third quarter of 2009.item.
As of SeptemberJune 30, 2010,2011, it is reasonably possible that approximately $44$46 million of unrecognized income tax benefits may be resolved within the next twelve months, of which less than $1approximately $4 million, if recognized, would affect FirstEnergy’s effective tax rate. The potential decrease in the amount of unrecognized income tax benefits is primarily associated with issues related to gains and losses from the disposition of assets and the capitalization of certain costs.
In 2009, FirstEnergy, on behalf of the Utilities, filed a change in accounting method related to the costs to repair and maintain electric utility network (transmission and distribution) assets. In the third quarter of 2010, approximately $325 million of costs were included as a repair deduction on FirstEnergy’s 2009 consolidatedvarious state tax return, which reduced taxable income and increased the amount of tax refunds that will be applied to FirstEnergy’s 2010 estimated federal tax payments. Due to Pennsylvania’s state flow through tax benefit for this change in accounting, FirstEnergy’s effective tax rate was reduced by $6 million in the third quarter of 2010. In connection with completing FirstEnergy’s 2009 consolidated tax return, FES recognized an $8 million adjustment that increased its income tax expense in the third quarter of 2010. The effects of the adjustment are not material to the quarterly and annual periods in 2009 or for the nine months ended September 30, 2010.items.
FirstEnergy recognizes interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized and the amount previously taken or expected to be taken on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes. The interest associated with the settlement of the claim noted above favorably affected FirstEnergy’s effective tax rate by $6 million in the first half of 2011. During the first six months of 2011, there were no material changes to the amount of accrued interest, except for a $6 million increase in accrued interest as a result of the merger with Allegheny. The reversal of accrued interest associated with the recognized income tax benefits noted above favorably affected FirstEnergy’s effective tax rate by $13$11 million in the first ninesix months of 2010. During the first nine months of 2009, there were no material changes to the amount of interest accrued. The net amount of accumulated interest accrued as of SeptemberJune 30, 20102011 was $6$10 million, as compared to $21with $3 million as of December 31, 2009.2010.

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As a result of the non-deductible portion of merger transaction costs, FirstEnergy’s effective tax rate was unfavorably impacted by $28 million in the first six months of 2011.
As a result of the Patient Protection and Affordable Care Act and the Health Care and Education Affordability Reconciliation Act signed into law onin March 23, 2010, and March 30, 2010, respectively, beginning in 2013 the tax deduction available to FirstEnergy will be reduced to the extent that drug costs are reimbursed under the Medicare Part D retiree subsidy program. As retiree healthcare liabilities and related tax impacts areunder prior law were already reflected in FirstEnergy’s consolidated financial statements, the change resulted in a charge to FirstEnergy’s earnings in the first quarter of 2010 of approximately $13 million and a reduction in accumulated deferred tax assets associated with these subsidies. This change reflectsThat charge reflected the anticipated increase in income taxes that will occur as a result of the change in tax law.

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On September 27, 2010, the Small Business Jobs Act was signed into law, which extends 50% bonus first-year depreciation for one year to 2010. ManagementAllegheny is currently evaluating thisunder audit by the IRS for tax election which could have a material impact on taxable incomeyears 2007 and 2008. The 2009 federal return was filed and is subject to review. State tax returns for 2010tax years 2006 through 2009 remain subject to review in Pennsylvania, West Virginia, Maryland and could increase the amountVirginia for certain subsidiaries of tax refunds to be recognized in 2010 with a corresponding increase to accumulated deferred income taxes for this temporary tax item.
AE. FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS (2008-2010) and state tax authorities. Tax returns for all state jurisdictions are open from 2006-2009. The IRS began reviewing returns for the years 2001-2003 in July 2004 and several items were under appeal. In the fourth quarter of 2009, these items were settled at appeals and sent to Joint Committee on Taxation for final review. The federal audits for years 2004-2006 were completed in the third quarter of 2008 and several items are under appeal. The IRS began auditing the year 2007 in February 2007 under its Compliance Assurance Process program and completed the audit in the first quarter of 2009 with two items under appeal. Items under appeal for tax years 2006 and 2007 were settled and sent to Joint Committee on Taxation for final review in the second quarter and subsequently approved in the third quarter of 2010. The IRS began auditing the year 2008 in February 2008 and the audit was completed in July 2010 with one item under appeal. The 2009 tax year audit began in February 2009 and the 2010 tax year audit began in February 2010. Neither audit is expected to close before December 2010. Management believes that adequate reserves have been recognized and final settlement of these audits is not expected to have a material adverse effect on FirstEnergy’s financial condition or results of operations.
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 SeptemberJune 30, 2010,2011, outstanding guarantees and other assurances aggregated approximately $3.8 billion, consisting primarily of parental guarantees ($0.8 billion), subsidiaries’ guarantees ($2.52.6 billion), and surety bonds and LOCs ($0.50.4 billion).
FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate or hedge normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for the financing or refinancing by subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties’ claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy’s guarantee enables the counterparty’s legal claim to be satisfied by other FirstEnergy assets. TheFirstEnergy believes the likelihood is remote that such parental guarantees of $0.3$0.2 billion (included in the $0.8 billion discussed above) as of SeptemberJune 30, 20102011 would increase amounts otherwise payable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.
While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event,” the immediate posting of cash collateral, provision of an LOC or accelerated payments may be required of the subsidiary. As of SeptemberJune 30, 2010,2011, FirstEnergy’s maximum exposure under these collateral provisions was $419$625 million, consisting of $374$522 million due to a below investment grade credit rating of(of which $175$265 million is due to an acceleration of payment or funding obligation,obligation) and $45$103 million due to “material adverse event” contractual clauses. Additionally, stress case conditions of a credit rating downgrade or “material adverse event” and hypothetical adverse price movements in the underlying commodity markets would increase this amount to $511 million consisting of $463 million due to a below investment grade credit rating, of which $175 million is related to an acceleration of payment or funding obligation, and $48 million due to “material adverse event” contractual clauses.$666 million.
Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $84$136 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.
In addition to guarantees and surety bonds, FES’ contracts entered into by the Competitive Energy Services segment, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions whichthat require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ and AE Supply’s power portfolioportfolios as of SeptemberJune 30, 2010,2011 and forward prices as of that date, FES hasand AE Supply have posted collateral of $244 million.$138 million and $2 million, respectively. Under a hypothetical adverse change in forward prices (95% confidence level change in forward prices over a one yearone-year time horizon), FES would be required to post an additional $46 million.$17 million of collateral. Depending on the volume of forward contracts and future price movements, FEShigher amounts for margining could be required to post higher amounts for margining.be posted.

 

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In connection with FES’ obligations to post and maintain collateral under the two-year PSA entered into by FES and the Ohio Companies following the CBP auction on May 13-14, 2009, NGC entered into a Surplus Margin Guaranty in an amount up to $500 million. The Surplus Margin Guaranty is secured by an NGC FMB issued in favor of the Ohio Companies.
FES’ debt obligations are generally guaranteed by its subsidiaries, FGCO and NGC, and FES guarantees the debt obligations of each of FGCO and NGC. Accordingly, present and future holders of indebtedness of FES, FGCO and NGC willwould have claims against each of FES, FGCO and NGC, regardless of whether their primary obligor is FES, FGCO or NGC.
Signal Peak and Global Rail are borrowers under a $350 million syndicated two-year senior secured term loan facility due in October 2012. FirstEnergy, together with WMB Loan Ventures LLC and WMB Loan Ventures II LLC, the entities that share ownership in the borrowers with FEV, have provided a guaranty of the borrowers’ obligations under the facility. In addition, FEV and the other entities that directly own the equity interest in the borrowers have pledged those interests to the lenders under the term loan facility as collateral for the facility.
(B) ENVIRONMENTAL MATTERS
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. Compliance with environmental regulations could have a material adverse effect on FirstEnergy’s earnings and competitive position to the extent that FirstEnergy competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations.
CAA Compliance
FirstEnergy is required to meet federally-approved SO2SO2 and NOXNOx emissions regulations under the CAA. FirstEnergy complies with SO2 and NOx reduction requirements under the CAA and SIP(s) under the CAA by burning lower-sulfur fuel, combustion controls and post-combustion controls, generating more electricity from lower-emitting plants and/or using emission allowances. Violations can result in the shutdown of the generating unit involved and/or civil or criminal penalties.
The Sammis, Burger, Eastlake and Mansfield coal-fired plants are operated under a consent decree with the EPA and DOJ that requires reductions of 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, PennFutureJuly 2008, three complaints were filed a citizen suit under the CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations,against FGCO in the U.S. District Court for the Western District of Pennsylvania. In July 2008, three additional complaints were filed against FGCOPennsylvania seeking damages based on coal-fired 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”,manner,” one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint seeking certification as a class action with the eight named plaintiffs as the class representatives. A settlement was reached with PennFuture. FGCO believes the claims of the remaining plaintiffs are without merit and intends to defend itself against the allegations made in thosethese three complaints.
The states of New Jersey and Connecticut filed CAA citizen suits in 2007 alleging NSR violations at the Portland Generation Station against GenOn Energy, Inc. (formerly RRI Energy, Inc. (theand the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999) and Met-Ed. Specifically, these suits allege that “modifications” at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR permitting in violation of the CAA’s PSD program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. In September 2009, the Court granted Met-Ed’s motion to dismiss New Jersey’s and Connecticut’s claims for injunctive relief against Met-Ed, but denied Met-Ed’s motion to dismiss the claims for civil penalties. The parties dispute the scope of Met-Ed’s indemnity obligation to and from Sithe Energy.Energy, and Met-Ed is unable to predict the outcome of this matter.
In January 2009, the EPA issued a NOV to ReliantGenOn Energy, Inc. alleging NSR violations at the Portland Generation Stationcoal-fired plant based on “modifications” dating back to 19861986. On March 31, 2011, the EPA proposed emissions limits and compliance schedules to reduce SO2 air emissions by approximately 81% at the Portland Plant based on an interstate pollution transport petition submitted by New Jersey under Section 126 of the CAA. The NOV also alleged NSR violations at the Keystone and Shawville Stationscoal-fired plants based on “modifications” dating back to 1984. Met-Ed, JCP&L, as the former owner of 16.67% of the Keystone, Station, and Penelec, as former owner and operator of the Shawville, Station, are unable to predict the outcome of this matter.
In June 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. (Mission) alleging that “modifications” at the coal-fired Homer City Power StationPlant occurred sincefrom 1988 to the present without preconstruction NSR permitting in violation of the CAA’s PSD program. In May 2010, the EPA issued a second NOV to Mission, Energy Westside, Inc., Penelec, New York State Electric & Gas Corporation and others that have had an ownership interest in the Homer City Power Station containing in all material respects allegations identical allegations asto those included in the June 2008 NOV. On July 20, 2010,In January 2011, the statesDOJ filed a complaint against Penelec in the U.S. District Court for the Western District of Pennsylvania seeking injunctive relief against Penelec based on alleged “modifications” at Homer City between 1991 to 1994 without preconstruction NSR permitting in violation of the CAA’s PSD and Title V permitting programs. The complaint was also filed against the former co-owner, New York State Electric and Gas Corporation, and various current owners of Homer City, including EME Homer City Generation L.P. and affiliated companies, including Edison International. In January 2011, another complaint was filed against Penelec and the other entities described above in the U.S. District Court for the Western District of Pennsylvania seeking damages based on Homer City’s air emissions as well as certification as a class action and to enjoin Homer City from operating except in a “safe, responsible, prudent and proper manner.” Penelec believes the claims are without merit and intends to defend itself against the allegations made in the complaint, but, at this time, is unable to predict the outcome of this matter. In addition, the Commonwealth of Pennsylvania and the States of New Jersey and New York intervened and Pennsylvania provided Mission Energy Westside, Inc., Penelec, NYSEG and others that have had an ownership interest in thefiled separate complaints regarding Homer City Power Station a notification required 60 days prior to filing a citizen suit under the CAA.seeking injunctive relief and civil penalties. Mission Energy Westside, Inc. is seeking indemnification from Penelec, the co-owner and operator of the Homer City Power Station prior to its sale in 1999. On April 21, 2011, Penelec and all other defendants filed Motions to Dismiss all of the federal claims and the various state claims. Responsive and Reply briefs were filed on May 26, 2011 and June 17, 2011, respectively. 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 generatingcoal-fired plants. The EPA’s NOV alleges equipment replacements occurring during maintenance outages dating back to 1990 triggered the pre-construction permitting requirements under the PSD and NNSR programs. FGCO received a request for certain operating and maintenance information and planning information for these same generating plants and notification that the EPA is evaluating whether certain maintenance at the Eastlake generating plantPlant 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 Eastlake Plant. In June 2011, EPA issued another Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, specifically opacity limitations and requirements to continuously operate opacity monitoring systems at the Eastlake, generating plant.Lakeshore, Bay Shore and Ashtabula coal-fired plants. Also, in June 2011, FirstEnergy received an information request pursuant to section 114(a) of the CAA for certain operating maintenance and planning information, among other information regarding these plants. FGCO intends to comply with the CAA, including the EPA’s information requests but, at this time, is unable to predict the outcome of this matter.
In August 2000, AE received an information request pursuant to section 114(a) of the CAA letter from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the following ten coal-fired plants, which collectively include 22 electric generation units Albright, Armstrong, Fort Martin, Harrison, Hatfield’s Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island to determine compliance with the CAA and related requirements, including potential application of the NSR standards under the CAA, which can require the installation of additional air emission control equipment when the major modification of an existing facility results in an increase in emissions. AE has provided responsive information to this and a subsequent request but is unable to predict the outcome of this matter.
In May 2004, AE, AE Supply, MP and WP received a Notice of Intent to Sue Pursuant to CAA §7604 from the Attorneys General of New York, New Jersey and Connecticut and from the PA DEP, alleging that Allegheny performed major modifications in violation of the PSD provisions of the CAA at the following West Virginia coal-fired plants: Albright Unit 3; Fort Martin Units 1 and 2; Harrison Units 1, 2 and 3; Pleasants Units 1 and 2 and Willow Island Unit 2. The Notice also alleged PSD violations at the Armstrong, Hatfield’s Ferry and Mitchell coal-fired plants in Pennsylvania and identifies PA DEP as the lead agency regarding those facilities. In September 2004, AE, AE Supply, MP and WP received a separate Notice of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.
In June 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed suit against AE, AE Supply, MP, PE and WP in the United States District Court for the Western District of Pennsylvania alleging, among other things, that Allegheny performed major modifications in violation of the CAA and the Pennsylvania Air Pollution Control Act at the Hatfield’s Ferry, Armstrong and Mitchell Plants in Pennsylvania. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. A non-jury trial on liability only was held in September 2010. Plaintiffs filed their proposed findings of fact and conclusions of law in December 2010, Allegheny made its related filings in February 2011 and plaintiffs filed their responses in April 2011. The parties are awaiting a decision from the District Court, but there is no deadline for that decision.
In September 2007, Allegheny also received a NOV from the EPA alleging NSR and PSD violations under the CAA, as well as Pennsylvania and West Virginia state laws at the Hatfield’s Ferry and Armstrong Plants in Pennsylvania and the Fort Martin and Willow Island coal-fired plants in West Virginia.
FirstEnergy intends to vigorously defend against the CAA matters described above but cannot predict their outcomes.
State Air Quality Compliance
In early 2006, Maryland passed the Healthy Air Act, which imposes state-wide emission caps on SO2 and NOX, requires mercury emission reductions and mandates that Maryland join the RGGI and participate in that coalition’s regional efforts to reduce CO2 emissions. On April 20, 2007, Maryland became the 10th state to join the RGGI. The Healthy Air Act provides a conditional exemption for the R. Paul Smith coal-fired plant for NOX, SO2 and mercury, based on a PJM declaration that the plant is vital to reliability in the Baltimore/Washington DC metropolitan area, which PJM determined in 2006. Pursuant to the legislation, the Maryland Department of the Environment (MDE) passed alternate NOX and SO2 limits for R. Paul Smith, which became effective in April 2009. However, R. Paul Smith is still required to meet the Healthy Air Act mercury reductions of 80% beginning in 2010. The statutory exemption does not extend to R. Paul Smith’s CO2 emissions. Maryland issued final regulations to implement RGGI requirements in February 2008. Ten RGGI auctions have been held through the end of calendar year 2010. RGGI allowances are also readily available in the allowance markets, affording another mechanism by which to secure necessary allowances. On March 14, 2011, MDE requested PJM perform an analysis to determine if termination of operation at R. Paul Smith would adversely impact the reliability of electrical service in the PJM region under current system conditions. FirstEnergy is unable to predict the outcome of this matter.

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In January 2010, the WVDEP issued a NOV for opacity emissions at Allegheny’s Pleasants coal-fired plant. FirstEnergy is discussing with WVDEP steps to resolve the NOV including installing a reagent injection system to reduce opacity.
National Ambient Air Quality Standards
The EPA’s CAIR requires reductions of NOXNOx and SO2 emissions in two phases (2009/2010 and 2015), ultimately capping SO2SO2 emissions in affected states to 2.5 million tons annually and NOXNOx emissions to 1.3 million tons annually. In 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” In December 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s opinion. The Court ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOX“NOx SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the “8-hour” ozone NAAQS. In July 2010,2011, the EPA proposedfinalized the CleanCross-State Air TransportPollution Rule (CATR)(CSAPR) to replace CAIR, which remains in effect until CSAPR becomes effective (60 days after publication in the EPA finalizes CATR. CATRFederal Register). CSAPR requires reductions of NOXNOx and SO2SO2 emissions in two phases (2012 and 2014), ultimately capping SO2SO2 emissions in affected states to 2.62.4 million tons annually and NOXNOx emissions to 1.31.2 million tons annually. The EPA proposed a preferred regulatory approach thatCSAPR allows trading of NOXNOx and SO2 emission allowances between power plants located in the same state and severely limits interstate trading of NOx and SO2 emission allowances. The EPA also requested comment on two alternative approaches—the first eliminates interstate trading of NOX and SO2 emission allowances and the second eliminates trading of NOX and SO2 emission allowances in its entirety. Depending on the actions taken by the EPA with respect to CATR, the proposed MACT regulations discussed below and any future regulations that are ultimately implemented,some restrictions. FGCO’s future cost of compliance may be substantial.substantial and changes to FirstEnergy’s operations may result. Management is currently assessing the impact of theseCSAPR, other environmental proposals and other factors on FGCO’sFirstEnergy’s competitive fossil generating facilities, particularlyincluding but not limited to, the impact on value of our emissions allowances (currently reflected at $38 million on our Consolidated Balance Sheet as of June 30, 2011) and the operationoperations of its smaller, non-supercritical units. For example, as disclosed herein, management decided to idle certain units or operate them on a seasonal basis until developments clarify.coal-fired plants.
Hazardous Air Pollutant Emissions
The EPA’s CAMR provides for a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping nationwide emissions of mercury at 38 tons by 2010 (as a “co-benefit” from implementation of SO2 and NOX emission caps under the EPA’s CAIR program) and 15 tons per year by 2018. The U.S. Court of Appeals for the District of Columbia, at the urging of several states and environmental groups, vacated the CAMR, ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. On April 29, 2010, the EPA issued proposed maximum achievable control technology (MACT) regulations requiring emissions reductions of mercury and other hazardous air pollutants from non-electric generating unit boilers, including boilers which do not use fossil fuels such as the proposed Burger biomass repowering project. On September 1, 2010, the EPA classified Burger as an existing source for purposes of the industrial Boiler MACT. If finalized, the non-electric generating unit MACT regulations could also provide precedent for MACT standards applicable to electric generating units. The EPA entered into a consent decree requiring it to propose MACT regulations for mercury and other hazardous air pollutants from electric generating units by March 16, 2011, the EPA released its MACT proposal to establish emission standards for mercury, hydrochloric acid and to finalize the regulations by November 16, 2011.various metals for electric generating units. Depending on the action taken by the EPA and on how any future regulations are ultimately implemented, FGCO’sFirstEnergy’s future cost of compliance with MACT regulations may be substantial and changes to FGCO’sFirstEnergy’s operations may result.
Climate Change
There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the House of Representatives passed one such bill, the American Clean Energy and Security Act of 2009, onin June 26, 2009. The Senate continues to consider a number of measures to regulate GHG emissions. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuringproposals to ensure that 10% of electricity used in the United States comes from renewable sources by 2012, increasingto increase to 25% by 2025, and implementingto implement an economy-wide cap-and-trade program to reduce GHG emissions by 80% by 2050. State activities,Certain states, primarily the northeastern states participating in the Regional Greenhouse Gas InitiativeRGGI and western states, led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.

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In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that will requirerequired FirstEnergy to measure GHG emissions commencing in 2010 and will require it to submit reports commencing in 2011. In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s finding concludes that concentrations of several key GHGs increase the threat of climate change and may be regulated as “air pollutants” under the CAA. In April 2010, the EPA finalized new GHG standards for model years 2012 to 2016 passenger cars, light-duty trucks and medium-duty passenger vehicles and clarified that GHG regulation under the CAA would not be triggered for electric generating plants and other stationary sources until January 2, 2011, at the earliest. In May 2010, the EPA finalized new thresholds for GHG emissions that define when permits under the CAA’s NSR program would be required. The EPA established an emissions applicability threshold of 75,000 tons per year (tpy) of carbon dioxide equivalents (CO2e)(CO2) effective January 2, 2011 for existing facilities under the CAA’s PSD program, but untilprogram. Until July 1, 2011, thatthis emissions applicability threshold will only apply if PSD is triggered by non-carbon dioxidenon-CO2 pollutants.
At the international level, the Kyoto Protocol, signed by the U.S. in 1998 but never submitted for ratification by the U.S. Senate, was intended to address global warming by reducing the amount of man-made GHG, including CO2, emitted by developed countries by 2012. A December 2009 U.N. Climate Change Conference in Copenhagen did not reach a consensus on a successor treaty to the Kyoto Protocol, but did take note of the Copenhagen Accord, a non-binding political agreement whichthat recognized the scientific view that the increase in global temperature should be below two degrees Celsius; includeincludes a commitment by developed countries to provide funds, approaching $30 billion over the next three years with a goal of increasing to $100 billion by 2020; and establishestablishes the “Copenhagen Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. OnceTo the extent that they have become a party to the Copenhagen Accord, developed economies, such as the European Union, Japan, Russia and the United States, would commit to quantified economy-wide emissions targets from 2020, while developing countries, including Brazil, China and India, would agree to take mitigation actions, subject to their domestic measurement, reporting and verification.

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On September 21,
In 2009, the U.S. Court of Appeals for the Second Circuit and on October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit reversed and remanded lower court decisions that had dismissed complaints alleging damage from GHG emissions on jurisdictional grounds. However, a subsequent ruling from the U.S. Court of Appeals for the Fifth Circuit reinstated the lower court dismissal of a complaint alleging damage from GHG emissions. These cases involve common law tort claims, including public and private nuisance, alleging that GHG emissions contribute to global warming and result in property damages. The U.S. Supreme Court granted a writ of certiorari to review the decision of the Second Circuit. On June 20, 2011, the U. S. Supreme Court reversed the Second Circuit. The Court remanded to the Second Circuit the issue of whether the CAA preempted state common law nuisance actions. The Court’s ruling also failed to answer the question of the extent to which actions for damages may remain viable. While FirstEnergy is not a party to this litigation, in June 2011, FirstEnergy and/or one or morereceived notice of its subsidiaries could be named in actions making similar allegations.a complaint alleging that the GHG emissions of 87 companies, including FirstEnergy, render them liable for damages to certain residents of Mississippi stemming from Hurricane Katrina. On July 27, 2011, the plaintiff voluntarily dismissed FirstEnergy from this complaint.
FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO2 emissions per KWH of electricity generated by FirstEnergy is lower than many of its regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy’s plants. In addition, Ohio, New Jersey and Pennsylvaniathe states in which FirstEnergy operates have water quality standards applicable to FirstEnergy’s operations.
TheIn 2004, 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). TheIn 2007, the Court of Appeals for the Second Circuit invalidated portions of the Section 316(b) performance standards and the EPA has taken the position that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. OnIn April 1, 2009, the U.S. Supreme Court reversed one significant aspect of the Second Circuit’s opinion and decided that Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. TheOn March 28, 2011, the EPA is developingreleased a new proposed regulation under Section 316(b) of the Clean Water Act consistent withgenerally requiring fish impingement to be reduced to a 12% annual average and studies to be conducted at the opinionsmajority of our existing generating facilities to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic life. On July 19, 2011, the Supreme Court andEPA extended the Court of Appeals which have created significant uncertainty aboutpublic comment period for the specific nature, scope and timing of thenew proposed Section 316(b) regulation by 30 days but stated its schedule for issuing a final performance standard.rule remains July 27, 2012. FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore power plant’s water intake channel to divert fish away from the plant’s water intake system. On March 15,In November 2010, the Ohio EPA issued a draft permit for the coal-fired Bay Shore power plantPlant requiring installation of reverse louvers in its entire water intake channel by December 31, 2014. Depending on the results of such studies and the EPA’s further rulemaking and any final action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

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In June 2008,April 2011, the U.S. Attorney’s Office in Cleveland, Ohio advised FGCO that it is no longer considering prosecution under the Clean Water Act and the Migratory Bird Treaty Act for three petroleum spills at the Edgewater, Lakeshore and Bay Shore plants which occurred on November 1, 2005, January 26, 2007 and February 27, 2007. This matter has been referred back to EPA for civil enforcement and FGCO is unable to predict the outcome of this matter.
In May 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club filed a CWA citizen suit alleging violations of arsenic limits in the NPDES water discharge permit for the fly ash disposal site at the Albright coal-fired plant seeking unspecified civil penalties and injunctive relief. MP is currently seeking relief from the arsenic limits through WVDEP agency review. In June 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club served another 60-Day Notice of Intent required prior to filing a citizen suit under the Clean Water Act for alleged failure to obtain a permit to construct the fly ash impoundments at the Albright Station.
FirstEnergy intends to vigorously defend against the CWA matters described above but cannot predict their outcomes.

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Monongahela River Water Quality
In late 2008, the PA DEP imposed water quality criteria for certain effluents, including TDS and sulfate concentrations in the Monongahela River, on new and modified sources, including the scrubber project at the Hatfield’s Ferry coal-fired plant. These criteria are reflected in the current PA DEP water discharge permit for that project. AE Supply appealed the PA DEP’s permitting decision, which would require it to incur significant costs or negatively affect its ability to operate the scrubbers as designed. Preliminary studies indicate an initial capital investment in excess of $150 million in order to install technology to meet the TDS and sulfate limits in the permit. The permit has been independently appealed by Environmental Integrity Project and Citizens Coal Council, which seeks to impose more stringent technology-based effluent limitations. Those same parties have intervened in the appeal filed by AE Supply, and both appeals have been consolidated for discovery purposes. An order has been entered that stays the permit limits that AE Supply has challenged while the appeal is pending. The hearing is scheduled to begin in September 2011, however the Court stayed all prehearing deadlines on July 15, 2011 to allow the parties additional time to work out a settlement. AE Supply intends to vigorously pursue these issues, but cannot predict the outcome of these appeals.
In a parallel rulemaking, the PA DEP recommended, and in August 2010, the Pennsylvania Environmental Quality Board issued, a final rule imposing end-of-pipe TDS effluent limitations. FirstEnergy could incur significant costs for additional control equipment to meet the requirements of this rule, although its provisions do not apply to electric generating units until the end of 2018, and then only if the EPA has not promulgated TDS effluent limitation guidelines applicable to such units.
In December 2010, PA DEP submitted its Clean Water Act 303(d) list to the EPA with a recommended sulfate impairment designation for an approximately 68 mile stretch of the Monongahela River north of the West Virginia border. In May 2011, the EPA agreed with PA DEP’s recommended sulfate impairment designation. PA DEP’s goal is to submit a final water quality standards regulation, incorporating the sulfate impairment designation for EPA approval by May, 2013. PA DEP will then need to develop a TMDL limit for the river, a process that will take approximately five years. Based on the stringency of the TMDL, FirstEnergy may incur significant costs to reduce sulfate discharges into the Monongahela River from its Hatfield’s Ferry and Mitchell facilities in Pennsylvania and its Fort Martin facility in West Virginia.
In October 2009, the WVDEP issued the water discharge permit for the Fort Martin generation facility. Similar to the Hatfield’s Ferry water discharge permit issued for the scrubber project, the Fort Martin permit imposes effluent limitations for TDS and sulfate concentrations. The permit also imposes temperature limitations and other effluent limits for heavy metals that are not contained in the Hatfield’s Ferry water permit. Concurrent with the issuance of the Fort Martin permit, WVDEP also issued an administrative order that sets deadlines for MP to meet certain of the effluent limits that are effective immediately under the terms of the permit. MP appealed the Fort Martin permit and the administrative order. The appeal included a request to stay certain of the conditions of the permit and order while the appeal is pending, which was granted pending a final decision on appeal and subject to WVDEP moving to dissolve the stay. The appeals have been consolidated. MP moved to dismiss certain of the permit conditions for the failure of the WVDEP to submit those conditions for public review and comment during the permitting process. An agreed-upon order that suspends further action on this appeal, pending WVDEP’s release for public review and comment on those conditions, was entered on August 11, 2010. The stay remains in effect during that process. The current terms of the Fort Martin permit would require MP to incur significant costs or negatively affect operations at Fort Martin. Preliminary information indicates an initial capital investment in excess of the capital investment that may be needed at Hatfield’s Ferry in order to install technology to meet the TDS and sulfate limits in the Fort Martin permit, which technology may also meet certain of the other effluent limits in the permit. Additional technology may be needed to meet certain other limits in the permit. MP intends to vigorously pursue these issues but cannot predict the outcome of these appeals.
Regulation of Waste Disposal
Federal and state hazardous waste regulations have been promulgated as a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976. Certain fossil-fuel combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation. In February 2009, the EPA requested comments from the states on options for regulating coal combustion residuals, including whether they should be regulated as hazardous or non-hazardous waste.
OnIn December 30, 2009, in an advanced notice of public rulemaking, the EPA saidasserted that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. OnIn May 4, 2010, the EPA proposed two options for additional regulation of coal combustion residuals, including the option of regulation as a special waste under the EPA’s hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. FGCO’sFirstEnergy’s future cost of compliance with any coal combustion residuals regulations whichthat may be promulgated could be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the EPA or the states.
The UtilitiesLittle Blue Run (LBR) Coal Combustion By-products (CCB) impoundment is expected to run out of disposal capacity for disposal of CCBs from the Bruce Mansfield Plant between 2016 and 2018. In July 2011, BMP submitted a Phase I permit application to PA DEP for construction of a new dry CCB disposal facility adjacent to LBR. BMP anticipates submitting zoning applications for approval to allow construction of a new dry CCB disposal facility prior to commencing construction.

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The Utility Registrants have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the consolidated balance sheet as of SeptemberJune 30, 2010,2011, based on estimates of the total costs of cleanup, the Utilities’Utility Registrants’ proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $105$133 million (JCP&L — $76$69 million, TE — $1 million, CEI — $1 million, FGCO — $1 million and FirstEnergy — $26$61 million) have been accrued through SeptemberJune 30, 2010.2011. Included in the total are accrued liabilities of approximately $67$63 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. On July 11, 2011, FirstEnergy was found to be a potentially responsible party under CERCLA indirectly liable for a portion of past and future clean-up costs at certain legacy MGP sites, estimated to total approximately $59 million. FirstEnergy recognized additional expense of $29 million during the second quarter of 2011; $30 million had previously been reserved prior to 2011.
(C) OTHER LEGAL PROCEEDINGS
Power Outages and Related Litigation
In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L’s territory.&L. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages due to the outages. After various motions, rulings and appeals, the Plaintiffs’ claims for consumer fraud, common law fraud, negligent misrepresentation, strict product liability and punitive damages were dismissed, leaving only the negligence and breach of contract causes of actions. On July 29, 2010, the Appellate Division upheld the trial court’s decision decertifying the class. Plaintiffs have filed, and JCP&L has opposed, a motion for leave to appeal to the New Jersey Supreme Court. JCP&L is waiting forIn November 2010, the Supreme Court issued an order denying Plaintiffs’ motion. The Court’s decision.
Litigation Relating toorder effectively ends the Proposed Allegheny Energy Merger
In connection with the proposed merger (Note 16), purported shareholders of Allegheny Energy have filed putative shareholder class action and/or derivative lawsuits against Allegheny Energyattempt, and its directors and certain officers, referredleaves only nine (9) plaintiffs to as the Allegheny Energy defendants, FirstEnergy and Merger Sub. Four putative class action and derivative lawsuits were filed in the Circuit Court for Baltimore City, Maryland (Maryland Court). One was withdrawn.pursue their respective individual claims. The Maryland Court has consolidated the remaining three cases under the caption: In re Allegheny Energy Shareholder and Derivative Litigation, C.A. No. 24-C-10-1301. Three shareholder lawsuits were filed in the Court of Common Pleas of Westmoreland County, Pennsylvania and the court has consolidated these actions under the caption: In re Allegheny Energy, Inc. Shareholder Class and Derivative, Litigation, Lead Case No. 1101 of 2010. One putative shareholder class action was filed in the U.S. District Court for the Western District of Pennsylvania and is captioned Louisiana Municipal Police Employees’ Retirement System v. Evanson, et al., C.A. No. 10-319 NBF. In summary, the lawsuits allege, among other things, that the Allegheny Energy directors breachedindividual plaintiffs have yet to take any affirmative steps to pursue their fiduciary duties by approving the merger agreement, and that

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Allegheny Energy, FirstEnergy and Merger Sub aided and abetted in these alleged breaches of fiduciary duty. The complaints seek, among other things, jury trials, money damages and injunctive relief. While FirstEnergy believes the lawsuits are without merit and has defended vigorously against the claims, in order to avoid the costs associated with the litigation, the defendants have agreed to the terms of a disclosure-based settlement of all these shareholder lawsuits and have reached agreement with counsel for all of the plaintiffs concerning fee applications. Under the terms of the settlement, no payments are being made by FirstEnergy or Merger Sub. A formal stipulation of settlement was filed with the Maryland Court on October 18, 2010 and agreements have been signed with plaintiffs in the Pennsylvania proceedings to dismiss those actions once the settlement is approved by the Maryland Court. The Maryland judge has preliminarily approved the stipulation of settlement and set the final approval hearing date for December 13, 2010. If the parties are unable to obtain final approval of the settlement, then litigation will proceed, and the outcome of any such litigation is inherently uncertain. If a dismissal is not granted or a settlement is not reached, these lawsuits could prevent or delay the completion of the merger and result in substantial costs to FirstEnergy. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger closes may adversely affect FirstEnergy’s business, financial condition or results of operations.individual claims.
Nuclear Plant Matters
During a planned refueling outage that began on February 28, 2010, FENOC conducted a non destructive examination and testing of the Control Rod Drive Mechanism (CRDM) nozzles of the Davis-Besse reactor pressure vessel head. FENOC identified flaws in CRDM nozzles that required modification. The NRC was notified of these findings, along with federal, state and local officials. On March 17, 2010, the NRC sent a special inspection team to Davis-Besse to assess the adequacy of FENOC’s identification, analyses and resolution of the CRDM nozzle flaws and to ensure acceptable modifications were made prior to placing the RPV head back in service. After successfully completing the modifications, FENOC committed to take a number of corrective actions including strengthening leakage monitoring procedures and shutting Davis-Besse down no later than October 1, 2011, to replace the reactor pressure vessel head with nozzles made of material less susceptible to primary water stress corrosion cracking, further enhancing the safe and reliable operations of the plant. On June 29, 2010, FENOC returned Davis-Besse to service. On September 9, 2010, the NRC held a public exit meeting describing the results of the NRC special inspection team inspection of FENOC’s identification of the CRDM nozzles with flaws and the modifications to those nozzles. On October 22, 2010, the NRC issued its final report of the special inspection. The report contained three findings characterized as very low safety significance that were promptly corrected prior to plant operation.
On April 5, 2010, the Union of Concerned Scientists (UCS) requested that the NRC issue a Show Cause Order, or otherwise delay the restart of the Davis-Besse Nuclear Power Station until the NRC determines that adequate protection standards have been met and reasonable assurance exists that these standards will continue to be met after the plant’s operation is resumed. By a letter dated July 13, 2010, the NRC denied UCS’s request for immediate action because “the NRC has conducted rigorous and independent assessments of returning the Davis-Besse reactor vessel head to service and its continued operation, and determined that it was safe for the plant to restart.” The UCS petition was referred to a petition manager for further review. What additional actions, if any, that the NRC takes in response to the UCS request have not been determined.
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of obligations. As of SeptemberJune 30, 2010,2011, FirstEnergy had approximately $2.0$2 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As required by the NRC, FirstEnergy providesannually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy’s NDT fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy’s obligation to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the NDT. The NRC issued guidance anticipating an additional $15increase in low-level radioactive waste disposal costs associated with the decommissioning of nuclear facilities. On March 28, 2011, FENOC submitted its biennial report on nuclear decommissioning funding to the NRC. This submittal identified a total shortfall in nuclear decommissioning funding for Beaver Valley Unit 1 and Perry of approximately $92.5 million. On June 24, 2011, FENOC submitted a $95 million parental guarantee associatedto the NRC for its approval.
In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse Nuclear Power Station operating license for an additional twenty years, until 2037. By an order dated April 26, 2011, a NRC Atomic Safety and Licensing Board (ASLB) granted a hearing on the Davis-Besse license renewal application to a group of petitioners. By this order, the ASLB also admitted two contentions challenging whether FENOC’s Environmental Report adequately evaluated (1) a combination of renewable energy sources as alternatives to the renewal of Davis-Besse’s operating license, and (2) severe accident mitigation alternatives at Davis-Besse. On May 6, 2011, FENOC filed an appeal with the fundingNRC Commissioners from the order granting a hearing on the Davis-Besse license renewal application.
On April 14, 2011, a group of decommissioningenvironmental organizations petitioned the NRC Commissioners to suspend certain pending nuclear licensing proceedings, including the Davis-Besse license renewal proceeding, to ensure that any safety and environmental implications of the accident at the Fukushima Daiichi Nuclear Power Station in Japan are considered. By May 2, 2011, the NRC Staff, FENOC and much of the nuclear industry filed responses opposing the petition. On May 6, 2011, petitioners filed a supplemental reply.
In January 2004, subsidiaries of FirstEnergy filed a lawsuit in the U.S. Court of Federal Claims seeking damages in connection with costs incurred at the Beaver Valley, Davis-Besse and Perry Nuclear facilities as a result of the DOE failure to begin accepting spent nuclear fuel on January 31, 1998. DOE was required to so commence accepting spent nuclear fuel by the Nuclear Waste Policy Act (42 USC 10101 et seq) and the contracts entered into by the DOE and the owners and operators of these facilities pursuant to the Act. On January 18, 2011, the parties, FirstEnergy and DOJ, filed a joint status report that established a schedule for the litigation of these claims. FirstEnergy filed damages schedules and disclosures with the DOJ on February 11, 2011, seeking approximately $57 million in damages for delay costs incurred through September 30, 2010. The damage claim is subject to review and audit by DOE.

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ICG Litigation
On December 28, 2006, AE Supply and MP filed a complaint in the Court of Common Pleas of Allegheny County, Pennsylvania against International Coal Group, Inc. (ICG), Anker West Virginia Mining Company, Inc. (Anker WV), and Anker Coal Group, Inc. (Anker Coal). Anker WV entered into a long term Coal Sales Agreement with AE Supply and MP for the supply of coal to the Harrison generating facility. Prior to the time of trial, ICG was dismissed as a defendant by the Court, which issue can be the subject of a future appeal. As a result of defendants’ past and continued failure to supply the contracted coal, AE Supply and MP have incurred and will continue to incur significant additional costs for these units.purchasing replacement coal. A non-jury trial was held from January 10, 2011 through February 1, 2011. At trial, AE Supply and MP presented evidence that they have incurred in excess of $80 million in damages for replacement coal purchased through the end of 2010 and will incur additional damages in excess of $150 million for future shortfalls. Defendants primarily claim that their performance is excused under a force majeure clause in the coal sales agreement and presented evidence at trial that they will continue to not provide the contracted yearly tonnage amounts. On May 2, 2011, the court entered a verdict in favor of AE Supply and MP for $104 million ($90 million in future damages and $14 million for replacement coal / interest). Post-trial filings occurred in May 2011, with Oral Argument on June 28, 2011. The parties expect a ruling sometime in the third quarter, at which time the judgment will be final. The parties have 30 days to appeal the final judgment. AE Supply and MP intend to vigorously pursue this matter through appeal if necessary but cannot predict its outcome.
Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.
OnIn February 16, 2010, a class action lawsuit was filed in Geauga County Court of Common Pleas against FirstEnergy, CEI and OE seeking declaratory judgment and injunctive relief, as well as compensatory, incidental and consequential damages, on behalf of a class of customers related to the reduction of a discount that had previously been in place for residential customers with electric heating, electric water heating, or load management systems. The reduction in the discount was approved by the PUCO. OnIn March 18, 2010, the named-defendant companies filed a motion to dismiss the case due to the lack of jurisdiction of the court of common pleas. The court granted the motion to dismiss on September 7, 2010. The plaintiffs appealed the decision to the Court of Appeals of Ohio, which has not yet rendered an opinion.
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.
FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy’s or its subsidiaries’ financial condition, results of operations and cash flows.

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10. REGULATORY MATTERS
(A) RELIABILITY INITIATIVES
Federally-enforceable mandatory reliability standards apply to the bulk powerelectric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES, FGCO, FENOC, ATSI and ATSI.TrAIL. The NERC is the ERO charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including ReliabilityFirstCorporation. All of FirstEnergy’s facilities are located within the ReliabilityFirstregion. FirstEnergy actively participates in the NERC and ReliabilityFirststakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by the ReliabilityFirstCorporation.
FirstEnergy believes that it generally is in compliance with all currently-effective and enforceable reliability standards. FirstEnergy’s practice is to address and resolve any occasional or isolated incidents of noncompliance as they ariseNevertheless, in the normal course of operations.operating its extensive electric utility systems and facilities, FirstEnergy also believesoccasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such items are found, FirstEnergy develops information about the item and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an item to ReliabilityFirst. Moreover, it is clear that the NERC, ReliabilityFirstand the FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with future new or amended standards cannot be determined at this time; however, 2005 amendments to the FPA provide that all prudent costs incurred to comply with the newfuture reliability standards be recovered in rates. Still, any future inability on FirstEnergy’s part to comply with the reliability standards for its bulk power system could result in the imposition of financial penalties that could have a material adverse effect on its financial condition, results of operations and cash flows.
On December 9, 2008, a transformer at JCP&L’s Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission voltage) lines out of the Oceanview and Atlantic substations resulting in customers losing power for up to eleven hours. On March 31, 2009, the NERC initiated a Compliance Violation Investigation in order to determine JCP&L’s contribution to the electrical event and to review any potential violation of NERC Reliability Standards associated with the event. NERC has submitted first and second Requests for Information regarding this and another related matter. JCP&L is complying with these requests. JCP&L is not able to predict what actions, if any, that the NERC may take with respect to this matter.

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On August 23, 2010, FirstEnergy self-reported to ReliabilityFirsta vegetation encroachment event on a Met-Ed 230 kV line to ReliabilityFirst.line. This event did not result in a fault, outage, operation of protective equipment, or any other meaningful electric effect on any FirstEnergy transmission facilities or systems. On August 25, 2010, ReliabilityFirstissued a Notice of Enforcement to investigate the incident. FirstEnergy submitted a data response to ReliabilityFirston September 27, 2010. AtIn March 2011, ReliabilityFirstsubmitted its proposed findings and settlement, although a final determination has not yet been made by FERC.
Allegheny has been subject to routine audits with respect to its compliance with applicable reliability standards and has settled certain related issues. In addition, ReliabilityFirstis currently conducting certain investigations with regard to certain matters of compliance by Allegheny.
(B) MARYLAND
By statute enacted in 2007, the obligation of Maryland utilities to provide standard offer service (SOS) to residential and small commercial customers, in exchange for recovery of their costs plus a reasonable profit, was extended indefinitely. The legislation also established a five-year cycle (to begin in 2008) for the MDPSC to report to the legislature on the status of SOS. PE now conducts rolling auctions to procure the power supply necessary to serve its customer load pursuant to a plan approved by the MDPSC. However, the terms on which PE will provide SOS to residential customers after the settlement beyond 2012 will depend on developments with respect to SOS in Maryland between now and then, including but not limited to possible MDPSC decisions in the proceedings discussed below.
The MDPSC opened a new docket in August 2007 to consider matters relating to possible “managed portfolio” approaches to SOS and other matters. “Phase II” of the case addressed utility purchases or construction of generation, bidding for procurement of demand response resources and possible alternatives if the TrAIL and PATH projects were delayed or defeated. It is unclear when the MDPSC will issue its findings in this and other SOS-related pending proceedings discussed below.
In September 2009, the MDPSC opened a new proceeding to receive and consider proposals for construction of new generation resources in Maryland. In December 2009, Governor Martin O’Malley filed a letter in this proceeding in which he characterized the electricity market in Maryland as a “failure” and urged the MDPSC to use its existing authority to order the construction of new generation in Maryland, vary the means used by utilities to procure generation and include more renewables in the generation mix. In August 2010, the MDPSC opened another new proceeding to solicit comments on the PJM RPM process. Public hearings on the comments were held in October 2010. In December 2010, the MDPSC issued an order soliciting comments on a model request for proposal for solicitation of long-term energy commitments by Maryland electric utilities. PE and numerous other parties filed comments, and at this time FirstEnergyno further proceedings have been set by the MDPSC in this matter.
In September 2007, the MDPSC issued an order that required the Maryland utilities to file detailed plans for how they will meet the “EmPOWER Maryland” proposal that electric consumption be reduced by 10% and electricity demand be reduced by 15%, in each case by 2015.
The Maryland legislature in 2008 adopted a statute codifying the EmPOWER Maryland goals. In 2008, PE filed its comprehensive plans for attempting to achieve those goals, asking the MDPSC to approve programs for residential, commercial, industrial, and governmental customers, as well as a customer education program. The MDPSC ultimately approved the programs in August 2009 after certain modifications had been made as required by the MDPSC, and approved cost recovery for the programs in October 2009. Expenditures were estimated to be approximately $101 million and would be recovered over the following six years. Meanwhile, extensive meetings with the MDPSC Staff and other stakeholders to discuss details of PE’s plans for additional and improved programs for the period 2012-2014 began in April 2011 and those programs are to be filed by September 1, 2011.
In March 2009, the MDPSC issued an order suspending until further notice the right of all electric and gas utilities in the state to terminate service to residential customers for non-payment of bills. The MDPSC subsequently issued an order making various rule changes relating to terminations, payment plans, and customer deposits that make it more difficult for Maryland utilities to collect deposits or to terminate service for non-payment. The MDPSC is unablecontinuing to predictconduct hearings and collect data on payment plan and related issues and has adopted a set of proposed regulations that expand the outcomesummer and winter “severe weather” termination moratoria when temperatures are very high or very low, from one day, as provided by statute, to three days on each occurrence.

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On March 24, 2011, the MDPSC held an initial hearing to discuss possible new regulations relating to service interruptions, storm response, call center metrics, and related reliability standards. The proposed rules included provisions for civil penalties for non-compliance. Numerous parties filed comments on the proposed rules and participated in the hearing, with many noting issues of this investigation.cost and practicality relating to implementation. The Maryland legislature passed a bill on April 11, 2011, which requires the MDPSC to promulgate rules by July 1, 2012 that address service interruptions, downed wire response, customer communication, vegetation management, equipment inspection, and annual reporting. In crafting the regulations, the legislation directs the MDPSC to consider cost-effectiveness, and provides that the MDPSC may adopt different standards for different utilities based on such factors as system design and existing infrastructure, geography, and customer density. Beginning in July 2013, the MDPSC is to assess each utility’s compliance with the standards, and may assess penalties of up to $25,000 per day per violation. The MDPSC has ordered that a working group of utilities, regulators, and other interested stakeholders meet to address the topics of the proposed rules, with proposed rules to be filed by September 15, 2011. Separately, on April 7, 2011, the MDPSC initiated a rulemaking with respect to issues related to contact voltage. On June 3, 2011, the MDPSC’s Staff issued a report and draft regulations. Comments on the draft regulations were submitted on June 17, 2011, and a hearing was held July 7, 2011. Final regulations related to contact voltage have not yet been adopted.
(B)(C) NEW JERSEY
In March 2009 and again in February 2010, JCP&L filed annual SBC Petitions with the NJBPU that included a requested zero level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009 estimated at $736 million (in 2003 dollars). In its order of June 15, 2011, the NJBPU adopted a Stipulation reached among JCP&L, the NJBPU Staff and the Division of Rate Counsel which resolved both Petitions, resulting in a net reduction in recovery of $0.8 million annually for all components of the SBC (including, as requested, a zero level of recovery of TMI-2 decommissioning costs).
(D) OHIO
The Ohio Companies operate under an Amended ESP, which expires on May 31, 2011, and provides for generation supplied through a CBP. The Amended ESP also allows the Ohio Companies to collect a delivery service improvement rider (Rider DSI) at an overall average rate of $0.002 per KWH for the period of April 1, 2009 through December 31, 2011. The Ohio Companies currently purchase generation at the average wholesale rate of a CBP conducted in May 2009. FES is one of the suppliers to the Ohio Companies through the May 2009 CBP. The PUCO approved a $136.6 million distribution rate increase for the Ohio Companies in January 2009, which went into effect on January 23, 2009 for OE ($68.9 million) and TE ($38.5 million) and on May 1, 2009 for CEI ($29.2 million). Applications for rehearing of the PUCO order in the distribution case were filed by the Ohio Companies and one other party. The Ohio Companies raised numerous issues in their application for rehearing related to rate recovery of certain expenses, recovery of line extension costs, the level of rate of return and the amount of general plant balances. The PUCO has not yet issued a substantive Entry on Rehearing.
On October 20, 2009, the Ohio Companies filed an MRO to procure, through a CBP, generation supply for customers who do not shop with an alternative supplier for the period beginning June 1, 2011. The CBP would be similar, in all material respects, to the CBP conducted in May 2009 in that it would procure energy, capacity and certain transmission services on a slice of system basis. However, unlike the May 2009 CBP, the MRO would include multiple bidding sessions and multiple products with different delivery periods for generation supply designed to reduce potential volatility and supplier risk and encourage bidder participation. Although the Ohio Companies requested a PUCO determination by January 18, 2010, on February 3, 2010, the PUCO announced that its determination would be delayed. The PUCO has not yet issued an order in this matter.
On March 23, 2010, the Ohio Companies filed an application for a new ESP. The new ESP will go into effect on June 1, 2011 and conclude on May 31, 2014. Attached to the application was a Stipulation and Recommendation signed by the Ohio Companies, the Staff of the PUCO, and an additional fourteen parties signing as Signatory Parties, with two additional parties agreeing not to oppose the adoption of the Stipulation. The material terms of the Stipulation includeESP include: generation supplied through a CBP similarcommencing June 1, 2011 (initial auctions held on October 20, 2010 and January 25, 2011); a load cap of no less than 80%, which also applies to the one used in May 2009 and the one proposed in the October 2009 MRO filing;tranches assigned post-auction; a 6% generation discount to certain low-incomelow income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (initial auctions scheduled for October 20, 2010 and January 25, 2011)(FES is one of the wholesale suppliers to the Ohio Companies); 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 agreeagreed not to collect certain amounts associated with RTEP and administrative costs associated with the move to PJM, dependent on the outcome of certain PJM proceedings. Many of the existing riders approved in the previous ESP remain in effect, some with modifications. The new ESP also requests the resolution of current proceedings pending at the PUCO regarding corporate separation, elements of the smart grid proceeding and the move to PJM. FirstEnergy recorded approximately $39.5 million of regulatory asset impairments and expenses related to the ESP. On May 12, 2010, a supplemental stipulation was filed that added two additional parties to the Stipulation, namely the City of Akron, Ohio and Council for Smaller Enterprises, to provide additional energy efficiency benefits. On July 22, 2010, a second supplemental stipulation was filed that, among other provisions provides a commitment thatrecover from retail customers of the Ohio Companies will not pay certain costs related to the companies’transmission cost allocations by PJM as a result of ATSI’s integration into PJM for the longer of the five yearfive-year period from June 1, 2011 through May 31, 20162015 or when the amount of costs avoided by customers for certain types of products totals $360 million dependent on the outcome of certain PJM proceedings, and establishesagreed to establish a $12 million fund to assist low income customers over the term of the ESP. Additional parties signing or not opposing the second supplemental stipulation include Northeast Ohio Public Energy Council (NOPEC), Northwest Ohio Aggregation Coalition (NOAC), Environmental LawESP and Policy Centeragreed to additional matters related to energy efficiency and a number of low income community agencies. The PUCO modified and approved the new ESP on August 25, 2010. The Companies accepted the PUCO’s decision subject to the implementation of certain elements of the ESP being consistent with the terms as they were included in the stipulation. On September 24, 2010, an application for rehearing was filed by the OCC and two other parties. The Ohio Companies and other parties filed their memorandum contra to that application for rehearing on October 4, 2010. The PUCO granted the application for rehearing on October 22, 2010. The PUCO has yet to rule on the substance of the application for rehearing.alternative energy requirements.
Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total annual energy savings equivalent ofto approximately 166,000 MWH in 2009, 290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in 2012 and 530,000 MWH in 2013, with additional savings required through 2025. Utilities arewere also required to reduce peak demand in 2009 by 1%, with an additional 0.75% reduction each year thereafter through 2018. The Ohio Companies filed an application with the PUCO seeking amendments to these benchmarks. On January 7, 2010, the PUCO amended the Ohio Companies’ 2009 energy efficiency benchmarks to zero, contingent upon the Ohio Companies meeting the revised benchmarks in a period of not more than three years. On March 10, 2010, the PUCO found that the Ohio Companies’ peak demand reduction programs complied with PUCO rules.
OnIn 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,issued an Opinion and Order generally approving the Ohio Companies’ compliance with3-year plan, and the Companies are in the process of implementing those programs included in the Plan. OE fell short of its statutory 2010 energy efficiency and peak demand reduction benchmarks is jeopardized and if not approved soon may requiretherefore, on January 11, 2011, it requested that its 2010 energy efficiency and peak demand reduction benchmarks be amended to actual levels achieved in 2010. The PUCO granted this request on May 19, 2011 for OE, finding that the motion was moot for CEI and TE. Moreover, because the PUCO indicated, when approving the 2009 benchmark request, that it would modify the Companies’ 2010 (and 2011 and 2012) energy efficiency benchmarks when addressing the portfolio plan, the Ohio Companies to seekwere not certain of their 2010 energy efficiency obligations. Therefore, CEI and TE (each of which achieved its 2010 energy efficiency and peak demand reduction statutory benchmarks) also requested an amendment if and only to the degree one was deemed necessary to bring them into compliance with their annual benchmark requirementsyet-to-be-defined modified benchmarks. On June 2, 2011, the Companies filed an application for 2010.rehearing to clarify the decision related to CEI and TE. Failure to comply with the benchmarks or to obtain such an amendment may subject the Companiescompanies to an assessment by the PUCO of a forfeiture.penalty. In addition to approving the programs included in the plan, with only minor modifications, the PUCO authorized the Companies to recover all costs related to the original CFL program that the Ohio Companies had previously suspended at the request of the PUCO. Applications for Rehearing were filed on April 22, 2011, regarding portions of the PUCO’s decision, including the method for calculating savings and certain changes made by the PUCO to specific programs. On May 4, 2011, the PUCO granted applications for rehearing for the purpose of further consideration; however, no substantive ruling has been issued.
Additionally under SB221, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they served in 2009.2009 and 0.50% of the KWH they served in 2010. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RFPs sought RECs, including solar RECs and RECs generated in Ohio in order to meet the Ohio Companies’ alternative energy requirements as set forth in SB221 for 2009, 2010 and 2011. The RECs acquired through these two RFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. OnIn March 10, 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market. The PUCOmarket and reduced the Ohio Companies’ aggregate 2009 benchmark to the level of solar RECs the Ohio Companies acquired through their 2009 RFP processes, provided the Ohio Companies’ 2010 alternative energy

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requirements be increased to include the shortfall for the 2009 solar REC benchmark. On April 15, 2010, the Ohio Companies and FES (due to its status as an electric service company in Ohio) filed compliance reports with the PUCO setting forth how they individually satisfied the alternative energy requirements in SB221 for 2009. FES also applied for a force majeure determination from the PUCO regarding a portion of their compliance with the 2009 solar energy resource benchmark. On February 23, 2011, the PUCO granted FES’ force majeure request for 2009 and increased its 2010 benchmark which application is still pending. In July 2010,by the amount of SRECs that FES was short of in its 2009 benchmark. On April 15, 2011, the Ohio Companies initiatedfiled an additional RFPapplication seeking an amendment to secure RECs and solar RECs needed to meet the Ohio Companies’each of their 2010 alternative energy requirements as set forthfor solar RECs generated in SB221. As a resultOhio on the basis that an insufficient quantity of this RFP, contracts were executedsolar resources are available in August 2010.the market but reflecting solar RECs that they have obtained and providing additional information regarding efforts to secure solar RECs. Other parties to the proceeding filed comments asserting that the force majeure determination should not be granted, and others requesting the PUCO to review the costs the Ohio companies’ have incurred to comply with the renewable energy requirements. The PUCO has not yet acted on that application.
OnIn February 12, 2010, OE and CEI filed an application with the PUCO to establish a new credit for all-electric customers. OnIn March 3, 2010, the PUCO ordered that rates for the affected customers be set at a level that will provide bill impacts commensurate with charges in place on December 31, 2008 and authorized the Ohio Companies to defer incurred costs equivalent to the difference between what the affected customers would have paid under previously existing rates and what they pay with the new credit in place. Tariffs implementing this new credit went into effect onin March 17, 2010. OnIn April 15, 2010, the PUCO issued a Second Entry on Rehearing that expanded the group of customers to which the new credit would apply and authorized deferral for the associated additional amounts. The PUCO also stated that it expected that the new credit would remain in place through at least the 2011 winter season and charged its staff to work with parties to seek a long term solution to the issue. Tariffs implementing this newly expanded credit went into effect in May 2010 and the proceeding remains open. The hearing on the matter was held in February 2011. The PUCO modified and approved the companies’ application on May 21, 2010. The Ohio Companies also25, 2011, ruling that the new credit be phased out over an eight-year period and granting authority for the companies to recover deferred costs and associated carrying charges. OCC filed on May 14, 2010 an applicationapplications for rehearing of the Second Entry on Rehearing, which was granted for purposes of further consideration on June 9, 2010. On September 9, 2010,24, 2011 and the OCC filed a motion requesting that a procedural schedule be established. The Ohio Companies filed their motion contraresponses on September 23, 2010.July 5, 2011. The PUCO Staff issued a report related to the all-electric issue on September 24, 2010, in which it provides backgroundhas not yet acted on the issue and sets forth its bill impact analysis under a number of different scenariosapplications for a longer term solution, but it made no specific recommendation to the PUCO.rehearing.

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(C)(E) PENNSYLVANIA
Met-Ed and Penelec purchase a portion of their POLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy sold to the extent needed for Met-Ed and Penelec to satisfy their POLR and default service obligations.
Met-Ed and Penelec filed with the PPUC a generation procurement plan covering the period January 1, 2011 through May 31, 2013. The plan is designed to provide adequate and reliable service via a prudent mix of long-term, short-term and spot market generation supply, as required by Act 129, with a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. On August 12, 2009, Met-Ed and Penelec filed a settlement agreement with the PPUC for the generation procurement plan, reflecting the settlement on all but two reserved issues. On November 6, 2009, the PPUC entered an Order approving the settlement and finding in favor of Met-Ed and Penelec on the two reserved issues. Generation procurement began in January 2010.
On February 8, 2010, Penn filed a Petition for Approval of its Default Service Plan for the period June 1, 2011 through May 31, 2013. On July 29, 2010, the parties to the proceeding filed a Joint Petition for Settlement of all issues. The PPUC adopted a Motion approving the Joint Petition for Settlement on October 21, 2010. The Joint Petition resolves all issues relating to Penn’s Default Service Plan for the next program period, including its procurement method, compliance with the Alternative Energy Portfolio Standards Act, rate design and retail market issues. The PPUC’s approval of the Joint Petition is conditioned by holding that the provision relating to the recovery of MISO exit cost fees and one-time PJM integration costs (resulting from Penn’s June 1, 2011 exit of MISO and integration into PJM) be approved, but made subject to the approval of cost recovery by FERC. Penn may not put these provisions into effect until FERC has approved the recovery and allocation of MISO exit fees and PJM integration costs. An Order consistent with the Motion is expected to be entered in the near future.
The PPUC adopted a Motion on January 28, 2010 and subsequently entered an Order on March 3, 2010 which deniesthat denied the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, and directsdirected Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructsinstructed Met-Ed and Penelec to work with the various intervening parties to file a recommendation to the PPUC regarding the establishment of a separate account for all marginal transmission losses collected from ratepayers plus interest to be used to mitigate future generation rate increases beginning January 1, 2011. OnIn March 18, 2010, Met-Ed and Penelec filed a Petition with the PPUC requesting that it stay the portion of the March 3, 2010 Order requiring the filing of tariff supplements to end collection of costs for marginal transmission losses. By Order entered March 25, 2010, theThe PPUC granted the requested stay until December 31, 2010. Pursuant to the PPUC’s order, Met-Ed and Penelec filed the planplans to establish separate accounts for marginal transmission loss revenues and related interest and carrying chargescharges. Pursuant to the plan approved by the PPUC, Met-Ed and Penelec began to refund those amounts to customers in January 2011, and the planrefunds will continue over a 29 month period until the full amounts previously recovered 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. Onmarginal transmission loses are refunded. In April 1, 2010, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania appealing the PPUC’s March 3, 2010 Order. On June 14, 2011, the Commonwealth Court issued an opinion and order affirming the PPUC’s Order to the extent that it holds that line loss costs are not transmission costs and, therefore, the approximately $254 million in marginal transmission losses and associated carrying charges for the period prior to January 1, 2011, are not recoverable under Met-Ed’s and Penelec’s TSC riders. Met-Ed and Penelec filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court and also a complaint seeking relief in federal district court. Although the ultimate outcome of this matter cannot be determined at this time, it is the belief of Met-Ed and Penelec believe that they should ultimately prevail inthrough the appealjudicial process and therefore expect to fully recover the approximately $199.7$254 million ($158.5189 million for Met-Ed and $41.2$65 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011. On July 9, 2010, Met-Ed
In May 2008, May 2009 and Penelec filed their briefs with the Commonwealth Court of Pennsylvania. The Office of Small Business Advocate filed its brief on July 9, 2010. On August 24, 2010, the PPUC as well as MEIUG and PICA filed their briefs. Met-Ed and Penelec filed their reply brief on September 9, 2010.
On May 20, 2010, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider for the periodannual periods between June 1, 2010 through2008 to December 31, 2010, including marginal transmission losses as approved by the PPUC, although the recovery of marginal losses will be subject to the outcome of the proceeding related to the 2008 TSC filing as described above. The PPUC’s approval in May 2010 authorized an increase to the TSC for Met-Ed’s customers was increased to provide for full recovery by December 31, 2010.
In February 2010, Penn filed a Petition for Approval of its Default Service Plan for the period June 1, 2011 through May 31, 2013. In July 2010, the parties to the proceeding filed a Joint Petition for Settlement of all issues. Although the PPUC’s Order approving the Joint Petition held that the provisions relating to the recovery of MISO exit fees and one-time PJM integration costs (resulting from Penn’s June 1, 2011 exit from MISO and integration into PJM) were approved, it made such provisions subject to the approval of cost recovery by FERC. Therefore, Penn may not put these provisions into effect until FERC has approved the recovery and allocation of MISO exit fees and PJM integration costs.
Pennsylvania adopted Act 129 was enacted in 2008 to address issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters; and alternative energy. Among other things, Act 129 required utilities to file with the PPUC an energy efficiency and peak load reduction plan, or EE&C Plan, by July 1, 2009, setting forth the utilities’ plans to reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of 4.5% by May 31, 2013. Act 129 also required utilities to file with the PPUC a Smart Meter Implementation Plan (SMIP).

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The PPUC entered an Order onin February 26, 2010 approvinggiving final approval to all aspects of the Pennsylvania Companies’ EE&C Plans of Met-Ed, Penelec and Penn and the tariff rider with rates effective March 1, 2010. On February 18, 2011, the companies filed a petition to approve their First Amended EE&C Plans. On June 28, 2011, a hearing on the petition was held before an administrative law judge.

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WP filed its original EE&C Plan in June 2009, which the PPUC approved, in large part, by Opinion and Order entered in October 2009. In November 2009, the Office of Consumer Advocate (OCA) filed an appeal with the Commonwealth Court of the PPUC’s October Order. The OCA contends that the PPUC’s Order failed to include WP’s costs for smart meter implementation in the EE&C Plan, and that inclusion of such costs would cause the EE&C Plan to exceed the statutory cap for EE&C expenditures. The OCA also contends that WP’s EE&C plan does not meet the Total Resource Cost Test. The appeal remains pending but has been stayed by the Commonwealth Court pending possible settlement of WP’s SMIP. In September 2010, WP filed an amended EE&C Plan that is less reliant on smart meter deployment, which the PPUC approved in January 2011.

Met-Ed, Penelec and Penn jointly filed a Smart Meter Technology Procurement and Installation PlanSMIP with the PPUC.PPUC in August 2009. This plan proposesproposed a 24-month assessment period in which the Pennsylvania CompaniesMet-Ed, Penelec and Penn will assess their needs, select the necessary technology, secure vendors, train personnel, install and test support equipment, and establish a cost effective and strategic deployment schedule, which currently is expected to be completed in fifteen years. Met-Ed, Penelec and Penn estimate assessment period costs atof approximately $29.5 million, which the Pennsylvania Companies,Met-Ed, Penelec and Penn, in their plan, proposed to recover through an automatic adjustment clause. The ALJ’s Initial Decision approved the Smart Meter PlanSMIP as modified by the ALJ, including: ensuring that the smart meters to be deployed include the capabilities listed in the PPUC’s Implementation Order; eliminatingdenying the provisionrecovery of interest inthrough the 1307(e) reconciliation;automatic adjustment clause; providing for the recovery of reasonable and prudent costs minusnet of resulting savings from installation and use of smart meters; and reflectingrequiring that administrative start-up costs be expensed and the costs incurred for research and development in the assessment period be capitalized. 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 onin June 9, 2010, consistent with the Chairman’s Motion. On June 24, 2010, Met-Ed, Penelec and Penn filed a Petition for Reconsideration of a single portion of the PPUC’s Order regarding the future ability to include smart meter costs in base rates. On August 5, 2010,rates, which the PPUC granted in part the petition for reconsideration by deleting language from its original order that would have precluded Met-Ed, Penelec and Penn from seeking to include smart meter costs in base rates at a later time. The costs to implement the SMIP could be material. However, assuming these costs satisfy a just and reasonable standard, they are expected to be recovered in a rider (Smart Meter Technologies Charge Rider) which was approved when the PPUC approved the SMIP.
In August 2009, WP filed its original SMIP, which provided for extensive deployment of smart meter infrastructure with replacement of all of WP’s approximately 725,000 meters by the end of 2014. In December 2009, WP filed a motion to reopen the evidentiary record to submit an alternative smart meter plan proposing, among other things, a less-rapid deployment of smart meters. In an Initial Decision dated April 29, 2010, an ALJ determined that WP’s alternative smart meter deployment plan, complied with the requirements of Act 129 and recommended approval of the alternative plan, including WP’s proposed cost recovery mechanism.
In light of the significant expenditures that would be associated with its smart meter deployment plans and related infrastructure upgrades, as well as its evaluation of recent PPUC decisions approving less-rapid deployment proposals by other utilities, WP re-evaluated its Act 129 compliance strategy, including both its plans with respect to smart meter deployment and certain smart meter dependent aspects of the EE&C Plan. In October 2010, WP and Pennsylvania’s OCA filed a Joint Petition for Settlement addressing WP’s smart meter implementation plan with the PPUC. Under the terms of the proposed settlement, WP proposed to decelerate its previously contemplated smart meter deployment schedule and to target the installation of approximately 25,000 smart meters in support of its EE&C Plan, based on customer requests, by mid-2012. The proposed settlement also contemplates that WP take advantage of the 30-month grace period authorized by the PPUC to continue WP’s efforts to re-evaluate full-scale smart meter deployment plans. WP currently anticipates filing its plan for full-scale deployment of smart meters in June 2012. Under the terms of the proposed settlement, WP would be permitted to recover certain previously incurred and anticipated smart-meter related expenditures through a levelized customer surcharge, with certain expenditures amortized over a ten-year period. Additionally, WP would be permitted to seek recovery of certain other costs as part of its revised SMIP that it currently intends to file in June 2012, or in a future base distribution rate case.
In December 2010, the PPUC directed that the SMIP proceeding be referred to the ALJ for further proceedings to ensure that the impact of the proposed merger with FirstEnergy is considered and that the Joint Petition for Settlement has adequate support in the record. On March 9, 2011, WP submitted an Amended Joint Petition for Settlement which restates the Joint Petition for Settlement filed in October 2010, adds the PPUC’s Office of Trial Staff as a signatory party, and confirms the support or non-opposition of all parties to the settlement. One party retained the ability to challenge the recovery of amounts spent on WP’s original smart meter implementation plan. The proposed settlement also obligates OCA to withdraw its November 2009 appeal of the PPUC’s Order in WP’s EE&C plan proceeding. A Joint Stipulation with the OSBA was also filed on March 9, 2011. On May 3, 2011, the ALJ issued an Initial Decision recommending that the PPUC approve the Amended Joint Petition for Full Settlement. The PPUC approved the Initial Decision by order entered June 30, 2011.

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By Tentative Order entered in September 17, 2009, the PPUC provided for an additional 30-day comment period on whether the 1998 Restructuring Settlement, which addressed how Met-Ed and Penelec were going to implement direct access to a competitive market for the generation of electricity, allows Met-Ed and Penelec to apply over-collection of NUG costs for select and isolated months to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists. In response to the Tentative Order, various parties filed comments objecting to the above accounting method utilized by Met-Ed and Penelec. Met-Ed and Penelec are awaiting further action by the PPUC.
In the PPUC Order approving the FirstEnergy and Allegheny merger, the PPUC announced that a separate statewide investigation into Pennsylvania’s retail electricity market will be conducted with the goal of making recommendations for improvements to ensure that a properly functioning and workable competitive retail electricity market exists in the state. On April 29, 2011, the PPUC entered an Order initiating the investigation and requesting comments from interested parties on eleven directed questions. Met-Ed, Penelec, Penn Power and West Penn submitted joint comments on June 3, 2011. FES also submitted comments on June 3, 2011. On June 8, 2011, the PPUC conducted an en banc hearing on these issues at which both the Pennsylvania Companies and FES participated and offered testimony.
(D) NEW JERSEY(F) VIRGINIA
JCP&L is permittedIn September 2010, PATH-VA filed an application with the VSCC for authorization to deferconstruct the Virginia portions of the PATH Project. On February 28, 2011, PATH-VA filed a motion to withdraw the application. On May 24, 2011, the VSCC granted PATH-VA’s motion to withdraw its application for future collection from customersauthorization to construct the amounts by which its costsVirginia portions of supplying BGS to non-shopping customers, costs incurred under NUG agreements,the PATH Project. See “Transmission Expansion” in the Federal Regulation and certain other stranded costs, exceed amounts collected through BGSRate Matters section for further discussion of this matter.
(G) WEST VIRGINIA
In August 2009, MP and NUGC rates and market sales of NUG energy and capacity. As of September 30, 2010,PE filed with the accumulated deferred cost balance was a credit of approximately $3 million. To better align the recovery of expected costs, on July 26, 2010, JCP&L filedWVPSC a request to decreaseincrease retail rates, which was amended through subsequent filings. MP and PE ultimately requested an annual increase in retail rates of approximately $95 million. In April 2010, MP and PE filed with the amount recovered forWVPSC a Joint Stipulation and Agreement of Settlement reached with 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 commentsother parties in the proceeding that provided for:
a $40 million annualized base rate increase effective June 29, 2010;
a deferral of February 2010 storm restoration expenses in November 2007. A scheduleWest Virginia over a maximum five-year period;
an additional $20 million annualized base rate increase effective in January 2011;
a decrease of $20 million in ENEC rates effective January 2011, which amount is deferred for later recovery in 2012; and
a moratorium on filing for further NJBPU proceedings has not yet been set. On March 13,increases in base rates before December 1, 2011, except under specified circumstances.
The WVPSC approved the Joint Petition and Agreement of Settlement in June 2010.
In 2009, JCP&L filed its annual SBC Petitionthe West Virginia Legislature enacted the Alternative and Renewable Energy Portfolio Act (Portfolio Act), which generally requires that a specified minimum percentage of electricity sold to retail customers in West Virginia by electric utilities each year be derived from alternative and renewable energy resources according to a predetermined schedule of increasing percentage targets, including ten percent by 2015, fifteen percent by 2020, and twenty-five percent by 2025. In November 2010, the WVPSC issued Rules Governing Alternative and Renewable Energy Portfolio Standard (RPS Rules), which became effective on January 4, 2011. Under the RPS Rules, on or before January 1, 2011, each electric utility subject to the provisions of this rule was required to prepare an alternative and renewable energy portfolio standard compliance plan and file an application with the NJBPUWVPSC seeking approval of such plan. MP and PE filed their combined compliance plan in December 2010. A hearing was held at the WVPSC on June 13, 2011. An order is expected by late September 2011.
Additionally, in January 2011, MP and PE filed an application with the WVPSC seeking to certify three facilities as Qualified Energy Resource Facilities. If the application is approved, the three facilities would then be capable of generating renewable credits which would assist the companies in meeting their combined requirements under the Portfolio Act. Further, in February 2011, MP and PE filed a petition with the WVPSC seeking an Order declaring that 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 matterMP is currently pending before the NJBPU.
New Jersey statutes require that the state periodically undertake a planning process, known as the EMP,entitled to addressall alternative and renewable 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 costsresource credits associated with the proposal.electric energy, or energy and capacity, that MP is required to purchase pursuant to electric energy purchase agreements between MP and three non-utility electric generating facilities in WV. The City of New Martinsville and Morgantown Energy Associates, each the owner of one of the contracted resources, has participated in the case in opposition to the Petition.

 

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(E)(H) FERC MATTERS
Rates for Transmission Service Between MISO and PJM
In November 2004, FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as SECA) during a 16-month transition period. In 2005, FERC set the SECA for hearing. The presiding ALJ issued an initial decision in August 2006, rejecting the compliance filings made by MISO, PJM and the transmission owners, and directing new compliance filings. This decision was subject to review and approval by FERC. In May 2010, FERC issued an order denying pending rehearing requests and an Order on Initial Decision which reversed the presiding ALJ’s rulings in many respects. Most notably, these orders affirmed the right of transmission owners to collect SECA charges with adjustments that modestly reduce the level of such charges, and changes to the entities deemed responsible for payment of the SECA charges. The Ohio Companies were identified as load serving entities responsible for payment of additional SECA charges for a portion of the SECA period (Green Mountain/Quest issue). FirstEnergy executed settlements with AEP, Dayton and the Exelon parties to fix FirstEnergy’s liability for SECA charges originally billed to Green Mountain and Quest for load that returned to regulated service during the SECA period. The AEP, Dayton and Exelon, settlements were approved by FERC in November 2010, and the relevant payments made. The subsidiaries of Allegheny entered into nine settlements to fix their liability for SECA charges with various parties. All of the settlements were approved by FERC and the relevant payments have been made for eight of the settlements. Payments due under the remaining settlement will be made as a part of the refund obligations of the Utilities that are under review by FERC as part of a compliance filing. Potential refund obligations of FirstEnergy and the Allegheny subsidiaries are not expected to be material. Rehearings remain pending in this proceeding.
PJM Transmission Rate
OnIn April 19, 2007, FERC issued an order (Opinion 494) finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate based on the amount of load served in a transmission zone. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a load flow methodology (DFAX), which is generally referred to as a “beneficiary pays” approach to allocating the cost of high voltage transmission facilities.
The FERC’s Opinion 494 order was appealed to the U.S. Court of Appeals for the Seventh Circuit, which issued a decision onin August 6, 2009. The court affirmed FERC’s ratemaking treatment for existing transmission facilities, but found that FERC had not supported its decision to allocate costs for new 500+ kV facilities on a load ratio share basis and, based on this finding, remanded the rate design issue back to FERC.
In an order dated January 21, 2010, FERC set the matter for a “paper hearings”hearing"—meaning that FERC called for parties to submit comments or written testimonycomments pursuant to the schedule described in the order. FERC identified nine separate issues for comments and directed PJM to file the first round of comments on February 22, 2010, with other parties submitting responsive comments and thethen reply comments.comments on later dates. PJM filed certain studies with FERC on April 13, 2010, in response to the FERC order. PJM’s filing demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain eastern utilities in PJM bearing the majority of theirthe costs. Numerous parties filed responsive comments or studies on May 28, 2010 and reply comments on June 28, 2010. FirstEnergy and a number of other utilities, industrial customers and state commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. Certain eastern utilities and their state commissions supported continued socialization of these costs on a load ratio share basis. This matter is awaiting action by FERC.
RTO Realignment
On June 1, 2011, ATSI and the ATSI zone entered into PJM. The move was performed as planned with no known operational or reliability issues for ATSI or for the wholesale transmission customers in the ATSI zone.
On February 1, 2011, ATSI in conjunction with PJM filed its proposal with FERC is expected to act beforefor moving its transmission rate into PJM’s tariffs. On April 1, 2011, the endMISO Transmission Owners (including ATSI) filed proposed tariff language that describes the mechanics of collecting and administering MTEP costs from ATSI-zone ratepayers. From March 20, 2011 through April 1, 2011, FirstEnergy, PJM and the MISO submitted numerous filings for the purpose of effecting movement of the year.
RTO Consolidation
On December 17, 2009, FERC issued an order approving, subjectATSI zone to certain future compliance filings, ATSI’s move to PJM. This move, which is expected to be effectivePJM on June 1, 2011, allows FirstEnergy2011. These filings include amendments to consolidate its transmission assetsthe MISO’s tariffs (to remove the ATSI zone), submission of load and operationsgeneration interconnection agreements to reflect the move into PJM. Currently, FirstEnergy’s transmission assets and operations are divided between PJM, and MISO. The consolidation will make the transmission assets that are partsubmission of ATSI, whose footprint includes the Ohio Companies and Penn, part of PJM. In the order, FERC approved FirstEnergy’s proposalchanges to use a Fixed Resource Requirement Plan (FRR Plan)PJM’s tariffs to obtain capacity to satisfy the PJM capacity requirements for the 2011-12 and 2012-13 delivery years.
On December 17, 2009, ATSI executed the PJM Consolidated Transmission Owners Agreement and on December 18, 2009, the Ohio Companies and Penn executed the PJM Operating Agreement and the PJM Reliability Assurance Agreement. Execution of these agreements committed ATSI, the Ohio Companies and Penn tosupport the move into PJM.
FirstEnergy successfully conductedOn May 31, 2011, FERC issued orders that address the FRR auctions on March 19, 2010. Moreover,proposed ATSI transmission rate, and certain parts of the ATSI-zone loads participated inMISO tariffs that reflect the mechanics of transmission cost allocation and collection. In its May 31, 2011 orders, FERC approved ATSI’s proposal to move the ATSI formula rate into the PJM base residual auctiontariff without significant change. Speaking to ATSI’s proposed treatment of the MISO’s exit fees and charges for the 2013 delivery year. Successful completion of these steps secured the capacity necessary fortransmission costs that were allocated to the ATSI footprintzone, FERC required ATSI to meet PJM’s capacity requirements.
present a cost-benefit study that demonstrates that the benefits of the move for transmission customers exceed the costs of any such move, which FERC had not previously required. Accordingly, FERC ruled that these costs must be removed from ATSI’s proposed transmission rates until such time as ATSI files and FERC approves the cost-benefit study. On September 4, 2009,June 30, 2011, ATSI submitted the PUCO opened a case to take comments from Ohio’s stakeholders regardingcompliance filing that removed the RTO consolidation. On August 25, 2010, the PUCO issued an order that, among other things, committed the PUCO to close this case and also to withdraw its objections that were filed in the relevant FERC dockets conditioned upon the Ohio Companies not seeking recovery of MISO exit fees orand transmission cost allocation charges from ATSI’s proposed transmission rates. Also on June 30, 2011, ATSI requested rehearing of FERC’s decision to require a cost-benefit study analysis as part of FERC’s evaluation of ATSI’s proposed transmission rates. The compliance filing, and ATSI’s request for rehearing, are currently pending before FERC.

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From late April 2011 through June 2011, FERC issued other orders that address ATSI’s move into PJM. These orders approve ATSI’s proposed interconnection agreements for large wholesale transmission customers and generators, and revisions to the PJM integrationand MISO tariffs that reflect ATSI’s move into PJM. In addition, FERC approved an “Exit Fee Agreement” that memorializes the agreement between ATSI and MISO with regard to ATSI’s obligation to pay certain administrative charges to the MISO upon exit. Finally, ATSI and the MISO were able to negotiate an agreement of ATSI’s responsibility for certain charges associated with long term firm transmission rights — that, according to the MISO, were payable by the ATSI zone upon its departure from the MISO. ATSI did not and does not agree that these costs (estimatedshould be charged to be approximately $37ATSI but, in order to settle the case and all claims associated with the case, ATSI agreed to a one-time payment of $1.8 million asto the MISO. This settlement agreement has been submitted for FERC’s review and approval. The final outcome of September 30, 2010). Notwithstandingthose proceedings that address the PUCO’s actions, certain other parties protested aspects of theremaining open issues related to ATSI’s move into PJM and certain of these matters remain outstanding and willtheir impact, if any, on FirstEnergy cannot be resolved in future FERC proceedings. Under the terms of the ESP order issued on August 25, 2010, the PUCO has agreed to closepredicted at this docket.time.
MISO Multi-Value Project Rule Proposal
OnIn July 15, 2010, MISO and certain MISO transmission owners jointly filed with FERC their proposed cost allocation methodology for certain new transmission projects. The new transmission projects—described as Multi-Value Projects (MVPs)MVPs —are a class of MTEP projects.transmission projects that are approved via MISO’s formal transmission planning process (the MTEP). The MISO proposesfiling parties proposed to allocate the costs of MVPs by means of a usage-based charge that will be applied to all loads within the MISO footprint, and to energy transactions that call for power to be “wheeled through” the MISO as well as to energy transactions that “source” in the MISO but “sink” outside of MISO. MISO expectsThe filing parties expect that itsthe MVP proposal will fund the costs of large transmission projects designed to bring wind generation from the upper Midwest to load centers in the east. MISO hasThe filing parties requested that FERC rule on its MVP proposal by December, but has asked for an effective date for itsthe proposal of July 16, 2011. On August 19, 2010, MISO’s Board approved the first MVP project—project — the so-called “Michigan Thumb Project.” Under MISO’s proposal, the costs of MVP projects approved by MISO’s Board prior to the anticipated June 1, 2011 effective date of FirstEnergy’s integration into PJM would continue to be allocated to FirstEnergy. This approach is reflected in the MISO’sMISO estimated allocations of the costs for the Michigan Thumb Project, wherethat approximately $16$15 million in annual revenue requirements werewould be allocated to the ATSI zone.zone associated with the Michigan Thumb Project upon its completion.

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OnIn September 10, 2010, FirstEnergy filed a protest to MISO’sthe MVP proposal. FirstEnergy believesproposal arguing that MISO’s proposal to allocate costs of MVPMVPs projects across the entire MISO footprint does not align with the established rule that cost allocation is to be based on cost causation (the “beneficiary pays” approach). FirstEnergy also argued that, in light of progress that had been made to date in the ATSI move tointegration into PJM, it would be unjust and unreasonable to allocate any MVP costs to the ATSI zone, or to ATSI. Numerous other parties filed pleadings on MISO’s MVP proposal.
In December 2010, FERC issued an order approving the MVP proposal without significant change. FERC’s order was not clear, however, as to whether the MVP costs would be payable by ATSI or load in the ATSI zone. FERC stated that the MISO’s tariffs obligate ATSI to pay all charges that attached prior to ATSI’s exit but ruled that the question of the amount of costs that are to be allocated to ATSI or to load in the ATSI zone were beyond the scope of FERC’s order and would be addressed in future proceedings.
On January 18, 2011, FirstEnergy filed for rehearing of FERC’s order. In its rehearing request, FirstEnergy argued that because the MVP rate is unableusage-based, costs could not be applied to ATSI, which is a stand-alone transmission company that does not use the transmission system. FirstEnergy also renewed its arguments regarding cost causation and the impropriety of allocating costs to the ATSI zone or to ATSI.
As noted above, on February 1, 2011, ATSI filed proposed transmission rates related to its move into PJM. The proposed rates included line items that were intended to recover all MVP costs (if any) that might be charged to ATSI or to the ATSI zone. In its May 31, 2011 order on ATSI’s proposed transmission rates FERC ruled that ATSI must submit a cost-benefit study before ATSI can recover the MVP costs. FERC further directed that ATSI remove the line-items from ATSI’s formula rate that would recover the MVP costs until such time as ATSI submits and FERC approves the cost- benefit study. ATSI requested a rehearing of these parts of FERC’s order and, pending this further legal process, has removed the MVP line items from its transmission rates.
FirstEnergy cannot predict the outcome of these proceedings at this time.
California Claims Matters
In October 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the California Department of Water Resources (CDWR) during 2001. The settlement proposal claims that CDWR is owed approximately $190 million for these alleged overcharges. This proposal was made in the context of mediation efforts by FERC and the United States Court of Appeals for the Ninth Circuit in pending proceedings to resolve all outstanding refund and other claims, including claims of alleged price manipulation in the California energy markets during 2000 and 2001. The Ninth Circuit has since remanded one of those proceedings to FERC, which arises out of claims previously filed with FERC by the California Attorney General on behalf of certain California parties against various sellers in the California wholesale power market, including AE Supply (the Lockyer case). AE Supply and several other sellers filed motions to dismiss the Lockyer case. In March 2010, the judge assigned to the case entered an opinion that granted the motions to dismiss filed by AE Supply and other sellers and dismissed the claims of the California Parties. On May 4, 2011, FERC affirmed the judge’s ruling.

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In June 2009, the California Attorney General, on behalf of certain California parties, filed a second complaint with FERC against various sellers, including AE Supply (the Brown case), again seeking refunds for trades in the California energy markets during 2000 and 2001. The above-noted trades with CDWR are the basis for including AE Supply in this new complaint. AE Supply filed a motion to dismiss the Brown complaint that was granted by FERC on May 24, 2011. On June 23, 2011, the California Attorney General requested rehearing of the May 24, 2011 order. FirstEnergy cannot predict the outcome of this matter.
Transmission Expansion
TrAIL Project.TrAIL is a 500 kV transmission line extending from southwest Pennsylvania through West Virginia and into northern Virginia. Effective May 19, 2011, all segments of TrAIL were energized and in service.
PATH Project.The PATH Project is comprised of a 765 kV transmission line that was proposed to extend from West Virginia through Virginia and into Maryland, modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland.
PJM initially authorized construction of the PATH Project in June 2007. In December 2010, PJM advised that its 2011 Load Forecast Report included load projections that are different from previous forecasts and that may have an impact on the proposed in-service date for the PATH Project. As part of its 2011 RTEP, and in response to a January 19, 2011 directive by a Virginia Hearing Examiner, PJM conducted a series of analyses using the most current economic forecasts and demand response commitments, as well as potential new generation resources. Preliminary analysis revealed the expected reliability violations that necessitated the PATH Project had moved several years into the future. Based on those results, PJM announced on February 28, 2011 that its Board of Managers had decided to hold the PATH Project in abeyance in its 2011 RTEP and directed FirstEnergy and AEP, as the sponsoring transmission owners, to suspend current development efforts on the project, subject to those activities necessary to maintain the project in its current state, while PJM conducts more rigorous analysis of the need for the project as part of its continuing RTEP process. PJM stated that its action did not constitute a directive to FirstEnergy and AEP to cancel or abandon the PATH Project. PJM further stated that it will complete a more rigorous analysis of the PATH Project and other transmission requirements and its Board will review this comprehensive analysis as part of its consideration of the 2011 RTEP. On February 28, 2011, affiliates of FirstEnergy and AEP filed motions or notices to withdraw applications for authorization to construct the project that were pending before state commissions in West Virginia, Virginia and Maryland. Withdrawal was deemed effective upon filing the notice with the MDPSC. The WVPSC and VSCC have granted the motions to withdraw.
PATH, LLC submitted a filing to FERC to implement a formula rate tariff effective March 1, 2008. In a November 19, 2010 order addressing various matters relating to the formula rate, FERC set the project’s base return on equity for hearing and reaffirmed its prior authorization of a return on CWIP, recovery of start-up costs and recovery of abandonment costs. In the order, FERC also granted a 1.5% return on equity incentive adder and a 0.50% return on equity adder for RTO participation. These adders will be applied to the base return on equity determined as a result of the hearing. PATH, LLC is currently engaged in settlement discussions with the staff of FERC and intervenors regarding resolution of the base return on equity.
Seneca Pumped Storage Project Relicensing
The Seneca (Kinzua) Pumped Storage Project is a 451 MW hydroelectric project located in Warren County, Pennsylvania owned and operated by FGCO. FGCO holds the current FERC license that authorizes ownership and operation of the project. The current FERC license will expire on November 30, 2015. FERC’s regulations call for a five-year relicensing process. On November 24, 2010, and acting pursuant to applicable FERC regulations and rules, FGCO initiated the relicensing process by filing its notice of intent to relicense and pre-application document (PAD) in the license docket.
On November 30, 2010, the Seneca Nation of Indians filed its notice of intent to relicense and PAD documents necessary for them to submit a competing application. Section 15 of the FPA contemplates that third parties may file a ‘competing application’ to assume ownership and operation of a hydroelectric facility upon (i) relicensure and (ii) payment of net book value of the plant to the original owner/operator. Nonetheless, FGCO believes it is entitled to a statutory “incumbent preference” under Section 15.
The Seneca Nation and certain other intervenors have asked FERC to redefine the “project boundary” of the hydroelectric plant to include the dam and reservoir facilities operated by the U.S. Army Corps. of Engineers. On May 16, 2011, FirstEnergy filed a Petition for Declaratory Order with FERC seeking an order to exclude the dam and reservoir facilities from the project. The Seneca Nation, the New York State Department of Environmental Conservation, and the U.S. Department of Interior each submitted responses to FirstEnergy’s petition, including motions to dismiss FirstEnergy’s petition. The “project boundary” issue is pending before FERC.

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The next steps in the relicensing process are for FirstEnergy and the Seneca Nation to define and perform certain environmental and operational studies to support their respective applications. These steps are expected to run through approximately November of 2013. FirstEnergy cannot predict the outcome of these proceedings at this time.
11. STOCK-BASED COMPENSATION PLANS
FirstEnergy has four types of stock-based compensation programs — LTIP, EDCP, ESOP and DCPD, as described below.
Allegheny’s stock-based awards were converted into FirstEnergy stock-based awards as of the date of the merger. These awards, referred to below as converted Allegheny awards, were adjusted in terms of the number of awards and, where applicable, the exercise price thereof, to reflect the merger’s common stock exchange ratio of 0.667 of a share of FirstEnergy common stock for each share of Allegheny common stock.
(A) LTIP
FirstEnergy’s LTIP includes four forms of stock-based compensation awards — stock options, performance shares, restricted stock and restricted stock units.
Under FirstEnergy’s LTIP, total awards cannot exceed 29.1 million shares of common stock or their equivalent. Only stock options, restricted stock and restricted stock units have currently been designated to be settled in common stock, with vesting periods ranging from two months to ten years. Performance share awards are currently designated to be paid in cash rather than common stock and therefore do not count against the limit on stock-based awards. There were 5.6 million shares available for future awards as of June 30, 2011.
Restricted Stock and Restricted Stock Units
Restricted common stock (restricted stock) and restricted stock unit (stock unit) activity was as follows:
Six Months
Ended
June 30, 2011
Restricted stock and stock units outstanding as of January 1, 20111,878,022
Granted891,881
Converted Allegheny restricted stock645,197
Exercised(428,686)
Forfeited(71,775)
Restricted stock and stock units outstanding as of June 30, 20112,914,639
The 891,881 shares of restricted common stock granted during the six months ended June 30, 2011 had a grant-date fair value of $33.2 million and a weighted-average vesting period of 2.74 years.
Restricted stock units include awards that will be settled in a specific number of shares of common stock after the service condition has been met. Restricted stock units also include performance-based awards that will be settled after the service condition has been met in a specified number of shares of common stock based on FirstEnergy’s performance compared to annual target performance metrics.
Compensation expense recognized during the six months ended June 30, 2011 and 2010 for restricted stock and restricted stock units, net of amounts capitalized, was approximately $27 million and $20 million, respectively.

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Stock Options
Stock option activity for the six months ended June 30, 2011 was as follows:
         
      Weighted 
      Average 
  Number of  Exercise 
Stock Option Activities Shares  Price 
         
Stock options outstanding as of January 1, 2011 (all exercisable)  2,889,066  $35.18 
Options granted  662,122   37.75 
Converted Allegheny options  1,805,811   41.75 
Options exercised  (691,304)  31.38 
Options forfeited/expired  (78,978)  71.71 
       
Stock options outstanding as of June 30, 2011  4,586,717  $38.09 
       
(3,924,595 options exercisable)        
Compensation expense recognized for stock options during the six months ended June 30, 2011 was $0.3 million. No expense was recognized during the six months ended June 30, 2010. Options granted during the six months ended June 30, 2011 had a grant-date fair value of $3.3 million and an expected weighted-average vesting period of 3.79 years.
Options outstanding by exercise price as of June 30, 2011 were as follows:
             
      Weighted  Remaining 
  Shares Under  Average  Contractual 
Exercise Prices Options  Exercise Price  Life in Years 
             
$20.02 – $30.74  1,045,122  $26.54   2.02 
$30.89 – $40.93  3,160,440   37.30   4.17 
$42.72 – $51.82  3,883   51.02   0.70 
$53.06 – $62.97  54,559   56.15   3.02 
$64.52 – $71.82  9,042   67.50   5.24 
$73.39 – $80.47  311,003   80.17   3.81 
$81.19 – $89.59  2,668   85.39   6.09 
          
Total  4,586,717  $38.08   3.64 
          
Performance Shares
Performance shares will be settled in cash and are accounted for as liability awards. Compensation expense (income) recognized for performance shares during the six months ended June 30, 2011 and 2010, net of amounts capitalized, totaled $2 million and $(6) million, respectively. No performance shares under the FirstEnergy LTIP were settled during the six months ended June 30, 2011 and 2010.
(B) ESOP
During 2011, shares of FirstEnergy common stock were purchased on the open market and contributed to participants’ accounts. Total ESOP-related compensation expense for the six months ended June 30, 2011 and 2010, net of amounts capitalized and dividends on common stock, were $19 million and $10 million, respectively.
(C) EDCP
There was no material compensation expense recognized on EDCP stock units during the six months ended June 30, 2011 and 2010.
(D) DCPD
DCPD expenses recognized during the six months ended June 30, 2011 and 2010 were approximately $2 million in each period. The net liability recognized for DCPD of approximately $6 million as of June 30, 2011 is included in the caption “Retirement benefits” on the Consolidated Balance Sheets.
Of the 1.7 million stock units authorized under the EDCP and DCPD, 1,076,779 stock units were available for future awards as of June 30, 2011.

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12. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
In 2010,May 2011, the FASB amended authoritative accounting guidance regarding fair value measurement. The amendment prohibits the Receivable Topicapplication of block discounts for all fair value measurements, permits the fair value of certain financial instruments to be measured on the basis of the FASB Accounting Standards Codificationnet risk exposure and allows the application of premiums or discounts to enhancethe extent consistent with the applicable unit of account. The amendment clarifies that the highest-and-best use and valuation-premise concepts are not relevant to financial instruments. Expanded disclosures are required under the amendment, including quantitative information about significant unobservable inputs used for Level 3 measurements, a qualitative discussion about the credit qualitysensitivity of financing receivablesrecurring Level 3 measurements to changes in unobservable inputs disclosed, a discussion of the Level 3 valuation processes, any transfers between Levels 1 and 2 and the allowance for credit losses. The update amends existing disclosures to require an entity to provide a greater levelclassification of disaggregated information aboutitems whose fair value is not recorded but is disclosed in the credit quality of its financing receivables and its allowance for credit losses. The amendment also requires an entity to disclose credit quality indicators, past due information, and modifications of its financing receivables.notes. The amendment is effective for interim and annual reporting periods ending on or after December 15, 2010. FirstEnergy is currently evaluatingin the impactfirst quarter of adopting2012. FirstEnergy does not expect this standardamendment to have a material effect on its financial statements.
In June 2011, the FASB issued new accounting guidance that revises the manner in which entities presents comprehensive income in their financial statements. The new guidance requires entities to report components of comprehensive income in either a continuous statement of comprehensive income or two separate but consecutive statements. The new guidance does not change the items that must be reported in other comprehensive income and does not affect the calculation or reporting of earnings per share. The amendment is effective for FirstEnergy in the first quarter of 2012. This amendment will not have a material effect on FirstEnergy’s financial statements.
12.13. 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 Ohiothe Allegheny merger in the fourthfirst quarter of 2009,2011, FirstEnergy reorganized its management structure, which resulted in changes to its operating segments to be consistent with the former Ohio Transitional Generation Servicesmanner in which management views the business. The new structure supports the combined company’s primary operations — distribution, transmission, generation and the marketing and sale of its products. The external segment was combinedreporting is consistent with the internal financial reporting used by FirstEnergy’s chief executive officer (its chief operating decision maker) to regularly assess the performance of the business and allocate resources. FirstEnergy now has three reportable operating segments — Regulated Distribution, Regulated Independent Transmission and Competitive Energy Services.
Prior to the change in composition of business segments, FirstEnergy’s business was comprised of two reportable operating segments. The Energy Delivery Services segment consistent with how management viewswas comprised of FirstEnergy’s then eight existing utility operating companies that transmit and distribute electricity to customers and purchase power to serve their POLR and default service requirements. The Competitive Energy Services segment was comprised of FES, which supplies electric power to end-use customers through retail and wholesale arrangements. The “Other/Corporate” segment consisted of corporate items and other businesses that were below the business.quantifiable threshold for separate disclosure. Disclosures for FirstEnergy’s operating segments for 20092010 have been reclassified to conform to the current presentation.
The changes in FirstEnergy’s reportable segments during 2011 consisted primarily of the following:
Energy Delivery Services was renamed Regulated Distribution and the operations of MP, PE and WP, which were acquired as part of the merger with Allegheny, and certain regulatory asset recovery mechanisms formerly included in the “Other” segment, transmitswere placed into this segment.
A new Regulated Independent Transmission segment was created consisting of ATSI, and the operations of TrAIL Company and FirstEnergy’s interest in PATH; TrAIL and PATH were acquired as part of the merger with Allegheny. The transmission assets and operations of JCP&L, Met-Ed, Penelec, MP, PE and WP remain within the Regulated Distribution segment.
AE Supply, an operator of generation facilities that was acquired as part of the merger with Allegheny, was placed into the Competitive Energy Services segment.
The Regulated Distribution segment distributes electricity through FirstEnergy’s eightten utility operating companies, serving 4.5approximately 6 million customers within 36,10067,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New Jersey,York, and purchases power for its POLR, SOS and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also includes the transmission operations of JCP&L, Met-Ed, Penelec, WP, MP and PE and the regulated electric generation facilities in West Virginia and New Jersey. ItsJersey which MP and JCP&L, respectively, own or contractually control.
The Regulated Distribution segment’s revenues are primarily derived from the delivery of electricity within FirstEnergy’s service areas, cost recovery of regulatory assets and the sale of electric generation service to retail customers who have not selected an alternative supplier (default(POLR, SOS or default service) in its Ohio, Pennsylvania andMaryland, New Jersey, Ohio and Pennsylvania franchise areas. Its results reflect the commodity costs of securing electric generation from FES and AE Supply and from non-affiliated power suppliers and the deferral and amortization of certain fuel costs.

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The Regulated Independent Transmission segment transmits electricity through transmission lines and its revenues are primarily derived from the formula rate recovery of costs and a return on investment for capital expenditures in connection with TrAIL, PATH and other projects and revenues from providing transmission services to electric energy providers, power marketers and receiving transmission-related revenues from operation of a portion of the FirstEnergy transmission system. Its results reflect the net PJM and MISO transmission expenses related to the delivery of the respective generation loads andloads. On June 1, 2011, the deferral and amortizationATSI transmission assets previously dedicated to MISO were integrated into the PJM market. All of certain fuel costs.FirstEnergy’s assets now reside in one RTO.
The Competitive Energy Services segment, through FES, supplies electric power to end-use customers through retail and wholesale arrangements, including associated company power sales to meet all or a portion of the POLR and default service requirements of FirstEnergy’s Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Maryland, Michigan and New Jersey. FES purchases the entire output of the 18 generating facilities which it owns and operates through its FGCO subsidiary (fossil and hydroelectric generating facilities) and owns, through its NGC subsidiary, FirstEnergy’s nuclear generating facilities. FENOC, a separate subsidiary of FirstEnergy, operates and maintains NGC’s nuclear generating facilities as well as the output relating to leasehold interests of OE and TE in certain of those facilities that are subject to sale and leaseback arrangements with non-affiliates, pursuant to full output, cost-of-service PSAs.
The Competitive Energy Services segment also includes Allegheny’s unregulated electric generation operations, including AE Supply and AE Supply’s interest in AGC. AE Supply owns, operates and controls the electric generation capacity of its 18 facilities. AGC owns and sells generation capacity to AE Supply and MP, which own approximately 59% and 41% of AGC, respectively. AGC’s sole asset is a 40% undivided interest in the Bath County, Virginia pumped-storage hydroelectric generation facility and its connecting transmission facilities. All of AGC’s revenues are derived from sales of its 1,109 MW share of generation capacity from the Bath County generation facility to AE Supply and MP.
This business segment controls approximately 14,000 MW20,000 MWs of capacity and also purchases electricity to meet sales obligations. The segment’s net income is primarily derived from affiliated and non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO (prior to June 1, 2011) to deliver energy to the segment’s customers.
The otherOther/Corporate segment contains corporate items and other businesses that are below the quantifiable threshold for separate disclosure as a reportable segment.
Financial information for each of FirstEnergy’s reportable segments is presented in the table below, which includes financial results for Allegheny beginning February 25, 2011. FES and the Utilities do not have separate reportable operating segments.

 

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Segment Financial Information
                                            
 Energy Competitive      Competitive Regulated       
 Delivery Energy Reconciling    Regulated Energy Independent Other/ Reconciling   
Three Months Ended Services Services Other Adjustments Consolidated  Distribution Services Transmission Corporate Adjustments Consolidated 
 (In millions)  (In millions) 
September 30, 2010
 
June 30, 2011
 
External revenues $2,757 $957 $11 $(32) $3,693  $2,485 $1,495 $105 $(30) $(7) $4,048 
Internal revenues 60 599 —  (659) —  — 318 — —  (306) 12 
                        
Total revenues 2,817 1,556 11  (691) 3,693  2,485 1,813 105  (30)  (313) 4,060 
Depreciation and amortization 287 62 6 3 358  240 107 18 7 — 372 
Investment income (loss), net 23 28 —  (5) 46  27 15 — 1  (12) 31 
Net interest charges 123 30 2 12 167  145 67 11 21 1 245 
Income taxes 137  (17) 5  (6) 119  108 7 18  (30)  (2) 101 
Net income (loss) 224  (27) —  (22) 175  184 12 31  (51)  (5) 171 
Total assets 22,773 11,076 604 254 34,707  26,932 17,146 2,339 1,179 — 47,596 
Total goodwill 5,551 24 — — 5,575  5,551 905 — — — 6,456 
Property additions 208 255 8  (1) 470  302 197 45 25 — 569 
 ��  
September 30, 2009
 
June 30, 2010
 
External revenues $2,942 490 6  (30) 3,408  $2,314 $795 $59 $(21) $(8) $3,139 
Internal revenues — 617 —  (617) —  19 539 — —  (558) — 
           
Total revenues 2,942 1,107 6  (647) 3,408 
Depreciation and amortization 373 69 3 4 449 
Investment income (loss), net 46 159 —  (14) 191 
Net interest charges 115 28 2 175 320 
Income taxes 99 121  (19)  (73) 128 
Net income 148 183 17  (118) 230 
Total assets 23,023 10,691 674 286 34,674 
Total goodwill 5,551 24 — — 5,575 
Property additions 182 224 14 12 432 
 
Nine Months Ended 
 
September 30, 2010
 
External revenues $7,673 2,453 21  (92) 10,055 
Internal revenues* 79 1,812 —  (1,824) 67 
                        
Total revenues 7,752 4,265 21  (1,916) 10,122  2,333 1,334 59  (21)  (566) 3,139 
Depreciation and amortization 888 194 25 7 1,114  264 71 13 3 — 351 
Investment income (loss), net 75 42 —  (24) 93  28 13 — —  (10) 31 
Net interest charges 369 94 4 39 506  124 33 5 9  (4) 167 
Income taxes 295 106  (14)  (23) 364  81 75 7  (12)  (17) 134 
Net income (loss) 481 174  (3)  (72) 580  132 121 11  (20) 12 256 
Total assets 22,773 11,076 604 254 34,707  21,457 11,102 993 914 — 34,466 
Total goodwill 5,551 24 — — 5,575  5,551 24 — — — 5,575 
Property additions 546 860 18 43 1,467  157 290 15 27 — 489 
  
September 30, 2009
 
Six Months Ended
 
 
June 30, 2011
 
External revenues $8,755 1,329 18  (89) 10,013  $4,753 $2,736 $172 $(53) $(16) $7,592 
Internal revenues — 2,349 —  (2,349) —  — 661 — —  (617) 44 
                        
Total revenues 8,755 3,678 18  (2,438) 10,013  4,753 3,397 172  (53)  (633) 7,636 
Depreciation and amortization 1,098 201 7 11 1,317  485 195 31 13 — 724 
Investment income (loss), net 111 136 —  (40) 207  52 21 — 1  (22) 52 
Net interest charges 338 64 5 252 659  276 122 20 40 — 458 
Income taxes 190 409  (56)  (113) 430  164 10 25  (50) 30 179 
Net income 285 614 52  (197) 754 
Net income (loss) 280 17 44  (86)  (39) 216 
Total assets 23,023 10,691 674 286 34,674  26,932 17,146 2,339 1,179 — 47,596 
Total goodwill 5,551 24 — — 5,575  5,551 905 — — — 6,456 
Property additions 524 893 133 25 1,575  479 411 72 56 — 1,018 
 
June 30, 2010
 
External revenues $4,798 $1,514 $116 $(43) $(14) $6,371 
Internal revenues 19 1,213 — —  (1,165) 67 
             
Total revenues 4,817 2,727 116  (43)  (1,179) 6,438 
Depreciation and amortization 577 148 25 6 — 756 
Investment income (loss), net 54 14 — 1  (22) 47 
Net interest charges 248 66 10 22  (7) 339 
Income taxes 143 117 14  (24)  (5) 245 
Net income (loss) 235 190 23  (39)  (4) 405 
Total assets 21,457 11,102 993 914 — 34,466 
Total goodwill 5,551 24 — — — 5,575 
Property additions 309 619 29 40 — 997 
*Under the accounting standard for the effects of certain types of regulation, internal revenues are not fully offset for sales of RECs by FES to the Ohio Companies that are retained in inventory.
Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting primarily consist of interest expense related to holding company debt, corporate support services revenues and expenses and elimination of intersegment transactions.
14. IMPAIRMENT OF LONG-LIVED ASSETS
FirstEnergy reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The recoverability of a long-lived asset is measured by comparing its carrying value to the sum of undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is greater than the undiscounted cash flows, impairment exists and a loss is recognized for the amount by which the carrying value of the long-lived asset exceeds its estimated fair value. The following events described in the sections below occurred during for the first six months of 2011 that indicated the carrying value of certain assets may not be recoverable.

 

5274

Fremont Energy Center
On March 11, 2011, FirstEnergy and American Municipal Power, Inc., entered into an agreement for the sale of Fremont Energy Center, which includes two natural gas combined-cycle combustion turbines and a steam turbine capable of producing 544 MW of load-following capacity and 163 MW of peaking capacity. The execution of this agreement triggered a need to evaluate the recoverability of the carrying value of the assets associated with the Fremont Energy Center. The estimated fair value of the Fremont Energy Center was based on the purchase price outlined in the sale agreement with American Municipal Power, Inc. The result of this evaluation indicated that the carrying cost of the Fremont Energy Center was not fully recoverable. As a result of the recoverability evaluation, FirstEnergy recorded an impairment charge of $11 million to operating income during the quarter ended March 31, 2011. On July 28, 2011, FirstEnergy closed the sale of Fremont Energy Center to American Municipal Power, Inc.
Peaking Facilities
During the first six months of 2011, FirstEnergy assessed the carrying values of certain peaking facilities that will more likely than not be sold or disposed of before the end of their useful lives. The estimated fair values were based on estimated sales prices quoted in an active market. The result of this evaluation indicated that the carrying costs of the peaking facilities were not fully recoverable. FirstEnergy recorded impairment charges of $7 million and $21 million during the three months and six months ended June 30, 2011, respectively, as a result of the recoverability evaluation.
13.15. ASSET RETIREMENT OBLIGATIONS
FirstEnergy has recognized applicable legal obligations for AROs and their associated cost for nuclear power plant decommissioning, reclamation of sludge disposal ponds and closure of coal ash disposal sites. In addition, FirstEnergy has recognized conditional asset retirement obligations (primarily for asbestos remediation).
The ARO liabilities for FES, OE and TE primarily relate to the decommissioning of the Beaver Valley, Davis-Besse and Perry nuclear generating facilities (OE for its leasehold interest in Beaver Valley Unit 2 and Perry and TE for its leasehold interest in Beaver Valley Unit 2). The ARO liabilities for JCP&L, Met-Ed and Penelec primarily relate to the decommissioning of the TMI-2 nuclear generating facility. FES, OE, JCP&L, Met-Ed and Penelec use an expected cash flow approach to measure the fair value of their nuclear decommissioning ARO.
During the first quarter of 2011, studies were completed to update the estimated cost of decommissioning the Perry nuclear generating facility. The cost studies resulted in a revision to the estimated cash flows associated with the ARO liabilities of FES and OE and reduced the liability for each subsidiary in the amounts of $40 million and $6 million, respectively.
During the second quarter of 2011, studies were completed to update the estimated cost of decommissioning the Davis-Besse nuclear facility. The cost studies resulted in a revision to the estimated cash flows associated with the ARO liabilities of FES and reduced the liability for FES in the amount of $5 million.
The revisions to the estimated cash flows had no significant impact on accretion of the obligation during the three months and six months ended June 30, 2011 when compared to the same periods of 2010.
16. SUPPLEMENTAL GUARANTOR INFORMATION
On July 13,In 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 ninesix month periods ended SeptemberJune 30, 20102011 and 2009,2010, consolidating balance sheets as of SeptemberJune 30, 20102011 and December 31, 20092010 and consolidating statements of cash flows for the ninethree months ended SeptemberJune 30, 20102011 and 20092010 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.

 

5375

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
                                        
For the Three Months Ended September 30, 2010 FES FGCO NGC Eliminations Consolidated 
For the Three Months Ended June 30, 2011 FES FGCO NGC Eliminations Consolidated 
 (In thousands)  (In millions) 
 
REVENUES
 $1,540,885 $645,001 $380,542 $(1,012,751) $1,553,677  $1,275 $535 $393 $(911) $1,292 
                      
  
EXPENSES:
  
Fuel 13,403 329,009 48,675 — 391,087  6 266 44 — 316 
Purchased power from affiliates 1,058,965 13,404 56,763  (1,012,751) 116,381  902 9 65  (911) 65 
Purchased power from non-affiliates 411,084 — — — 411,084  332  (3) — — 329 
Other operating expenses 84,169 97,322 116,112 12,190 309,793  159 115 143 12 429 
Provision for depreciation 752 23,845 36,005  (1,304) 59,298  1 32 36  (1) 68 
General taxes 6,216 8,875 6,713 — 21,804  16 8 6 — 30 
Impairment of long-lived assets — 291,934 — — 291,934  — 7 — — 7 
                      
Total expenses 1,574,589 764,389 264,268  (1,001,865) 1,601,381  1,416 434 294  (900) 1,244 
                      
  
OPERATING INCOME (LOSS)
  (33,704)  (119,388) 116,274  (10,886)  (47,704)  (141) 101 99  (11) 48 
                      
  
OTHER INCOME (EXPENSE):
  
Investment income 256 396 29,243 — 29,895  — 1 15 — 16 
Miscellaneous income (expense), including net income from equity investees 5,707 2,562 49  (3,553) 4,765  123 1 —  (120)  4 
Interest expense — affiliates  (60)  (2,021)  (416) —  (2,497) —  (1)  (1) —  (2)
Interest expense — other  (24,158)  (26,243)  (15,028) 15,885  (49,544)  (24)  (28)  (16) 16  (52)
Capitalized interest 95 19,024 3,836 — 22,955  — 5 5 — 10 
                      
Total other income (expense)  (18,160)  (6,282) 17,684 12,332 5,574  99  (22) 3  (104)  (24)
                      
  
INCOME BEFORE INCOME TAXES
  (51,864)  (125,670) 133,958 1,446  (42,130)
INCOME (LOSS) BEFORE INCOME TAXES
  (42) 79 102  (115) 24 
  
INCOME TAXES (BENEFITS)
  (15,138)  (44,364) 51,600 2,498  (5,404)  (62) 25 38 3 4 
                      
  
NET INCOME (LOSS)
 $(36,726) $(81,306) $82,358 $(1,052) $(36,726)
NET INCOME
 $20 $54 $64 $(118) $20 
                      

 

5476

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
                                        
For the Nine Months Ended September 30, 2010 FES FGCO NGC Eliminations Consolidated 
For the Six Months Ended June 30, 2011 FES FGCO NGC Eliminations Consolidated 
 (In thousands)  (In millions) 
  
REVENUES
 $4,203,610 $1,793,986 $1,145,795 $(2,886,947) $4,256,444  $2,642 $1,278 $862 $(2,098) $2,684 
                      
  
EXPENSES:
  
Fuel 25,768 910,739 125,212 — 1,061,719  7 560 92 — 659 
Purchased power from affiliates 2,940,360 25,646 167,173  (2,886,947) 246,232  2,087 11 134  (2,098) 134 
Purchased power from non-affiliates 1,160,119 — — — 1,160,119  629  (3) — — 626 
Other operating expenses 218,278 289,638 371,882 36,568 916,366  321 233 331 25 910 
Provision for depreciation 2,253 77,838 109,364  (3,920) 185,535  2 63 74  (3) 136 
General taxes 17,432 32,702 20,688 — 70,822  27 19 14 — 60 
Impairment charges of long-lived assets — 293,767 — — 293,767  — 20 — — 20 
                      
Total expenses 4,364,210 1,630,330 794,319  (2,854,299) 3,934,560  3,073 903 645  (2,076) 2,545 
                      
  
OPERATING INCOME (LOSS)
  (160,600) 163,656 351,476  (32,648) 321,884   (431) 375 217  (22) 139 
                      
  
OTHER INCOME (EXPENSE):
  
Investment income 3,964 531 39,483 — 43,978  1 1 20 — 22 
Miscellaneous income (expense), including net income from equity investees 323,371 1,638 50  (314,591) 10,468 
Miscellaneous income, including net income from equity investees 356 2 —  (350) 8 
Interest expense — affiliates  (179)  (5,917)  (1,266) —  (7,362)  (1)  (1)  (1) —  (3)
Interest expense — other  (71,793)  (80,548)  (46,152) 47,933  (150,560)  (48)  (56)  (33) 32  (105)
Capitalized interest 293 54,930 11,327 — 66,550  — 10 10 — 20 
                      
Total other income (expense) 255,656  (29,366) 3,442  (266,658)  (36,926) 308  (44)  (4)  (318)  (58)
                      
  
INCOME BEFORE INCOME TAXES
 95,056 134,290 354,918  (299,306) 284,958 
INCOME (LOSS) BEFORE INCOME TAXES
  (123) 331 213  (340) 81 
  
INCOME TAXES (BENEFITS)
  (82,069) 52,144 130,163 7,595 107,833   (179) 119 80 5 25 
                      
  
NET INCOME
 $177,125 $82,146 $224,755 $(306,901) $177,125  $56 $212 $133 $(345) $56 
                      

 

5577

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
                                        
For the Three Months Ended September 30, 2009 FES FGCO NGC Eliminations Consolidated 
For the Three Months Ended June 30, 2010 FES FGCO NGC Eliminations Consolidated 
 (In thousands)  (In millions) 
  
REVENUES
 $1,087,991 $477,679 $170,129 $(631,227) $1,104,572  $1,307 $581 $339 $(901) $1,326 
                      
  
EXPENSES:
  
Fuel 9,278 241,953 43,462 — 294,693  7 302 34 — 343 
Purchased power from affiliates 621,996 9,233 35,290  (631,229) 35,290  913 8 49  (901) 69 
Purchased power from non-affiliates 205,200 — — — 205,200  310 — — — 310 
Other operating expenses 70,246 109,828 113,669 12,192 305,935  81 94 117 12 304 
Provision for depreciation 1,051 30,469 35,832  (1,311) 66,041  1 27 36  (1) 63 
General taxes 4,351 11,331 6,018 — 21,700  6 9 7 — 22 
                      
Total expenses 912,122 402,814 234,271  (620,348) 928,859  1,318 440 243  (890) 1,111 
                      
  
OPERATING INCOME
 175,869 74,865  (64,142)  (10,879) 175,713 
OPERATING INCOME (LOSS)
  (11) 141 96  (11) 215 
                      
  
OTHER INCOME (EXPENSE):
  
Investment income 35 319 158,503 — 158,857  2 — 11 — 13 
Miscellaneous income (expense), including net income from equity investees 100,668 744 1  (98,609) 2,804 
Interest expense to affiliates  (35)  (1,267)  (907) —  (2,209)
Miscellaneous income, including net income from equity investees 151 1 —  (148) 4 
Interest expense — affiliates —  (2) — —  (2)
Interest expense — other  (15,358)  (26,737)  (16,205) 16,113  (42,187)  (24)  (28)  (15) 16  (51)
Capitalized interest 49 15,381 2,439 — 17,869  — 20 4 — 24 
                      
Total other income (expense) 85,359  (11,560) 143,831  (82,496) 135,134  129  (9) —  (132)  (12)
                      
  
INCOME BEFORE INCOME TAXES
 261,228 63,305 79,689  (93,375) 310,847  118 132 96  (143) 203 
  
INCOME TAXES
 61,545 19,646 27,801 2,172 111,164 
INCOME TAXES (BENEFITS)
  (16) 48 34 3 69 
                      
  
NET INCOME
 $199,683 $43,659 $51,888 $(95,547) $199,683  $134 $84 $62 $(146) $134 
                      

 

5678

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
                                        
For the Nine Months Ended September 30, 2009 FES FGCO NGC Eliminations Consolidated 
For the Six Months Ended June 30, 2010 FES FGCO NGC Eliminations Consolidated 
 (In thousands)  (In millions) 
 
REVENUES
 $3,357,873 $1,726,715 $955,452 $(2,368,210) $3,671,830  $2,674 $1,149 $765 $(1,874) $2,714 
                      
  
EXPENSES:
  
Fuel 16,400 755,632 99,128 — 871,160  12 582 77 — 671 
Purchased power from affiliates 2,351,879 16,333 149,746  (2,368,212) 149,746  1,881 12 111  (1,874) 130 
Purchased power from non-affiliates 551,155 — — — 551,155  760 — — — 760 
Other operating expenses 144,284 313,416 397,284 36,571 891,555  134 194 256 24 608 
Provision for depreciation 3,087 90,680 103,135  (3,940) 192,962  2 54 73  (3) 126 
General taxes 12,826 35,289 18,246 — 66,361  11 24 14 — 49 
Impairment of long-lived assets — 2 — — 2 
                      
Total expenses 3,079,631 1,211,350 767,539  (2,335,581) 2,722,939  2,800 868 531  (1,853) 2,346 
                      
  
OPERATING INCOME
 278,242 515,365 187,913  (32,629) 948,891 
OPERATING INCOME (LOSS)
  (126) 281 234  (21) 368 
                      
  
OTHER INCOME (EXPENSE):
  
Investment income 83 758 134,882 — 135,723  4 — 10 — 14 
Miscellaneous income (expense), including net income from equity investees 509,927 1,209 15  (498,311) 12,840 
Miscellaneous income, including net income from equity investees 317 1 —  (311) 7 
Interest expense to affiliates  (103)  (4,648)  (3,752) —  (8,503) —  (4)  (1) —  (5)
Interest expense — other  (20,778)  (72,762)  (46,050) 48,605  (90,985)  (48)  (54)  (31) 32  (101)
Capitalized interest 146 34,257 7,572 — 41,975  — 36 8 — 44 
                      
Total other income (expense) 489,275  (41,186) 92,667  (449,706) 91,050  273  (21)  (14)  (279)  (41)
                      
  
INCOME BEFORE INCOME TAXES
 767,517 474,179 280,580  (482,335) 1,039,941  147 260 220  (300) 327 
  
INCOME TAXES
 99,751 166,902 98,893 6,629 372,175 
INCOME TAXES (BENEFITS)
  (67) 97 78 5 113 
                      
  
NET INCOME
 $667,766 $307,277 $181,687 $(488,964) $667,766  $214 $163 $142 $(305) $214 
                      

 

5779

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)
                               
As of September 30, 2010 FES FGCO NGC Eliminations Consolidated 
As of June 30, 2011 FES FGCO NGC Eliminations Consolidated 
 (In thousands)  (In millions) 
ASSETS
  
 
CURRENT ASSETS:
  
Cash and cash equivalents $— $1 $9 $— $10  $— $6 $— $— $6 
Receivables-  
Customers 325,265 — — — 325,265  450 — — — 450 
Associated companies 299,222 193,951 112,523  (335,710) 269,986  481 425 263  (679) 490 
Other 34,052 4,831 18,524 — 57,407  24 23 4 — 51 
Notes receivable from associated companies 10,100 329,461 162,087 — 501,648  6 410 74 — 490 
Materials and supplies, at average cost 28,411 301,761 223,871 — 554,043  54 253 192 — 499 
Derivatives 221 — — — 221 
Prepayments and other 191,423 9,669 2,973 — 204,065  34 14 1 — 49 
                      
 888,473 839,674 519,987  (335,710) 1,912,424  1,270 1,131 534  (679) 2,256 
                      
  
PROPERTY, PLANT AND EQUIPMENT:
  
In service 94,787 4,640,027 5,313,456  (385,006) 9,663,264  101 6,105 5,634  (385) 11,455 
Less — Accumulated provision for depreciation 16,209 2,173,661 2,098,927  (174,416) 4,114,381  19 2,067 2,298  (178) 4,206 
                      
 78,578 2,466,366 3,214,529  (210,590) 5,548,883  82 4,038 3,336  (207) 7,249 
Construction work in progress 7,523 2,221,270 507,842 — 2,736,635  10 198 486 — 694 
Property, plant and equipment held for sale, net — 487 — — 487 
                      
 86,101 4,687,636 3,722,371  (210,590) 8,285,518  92 4,723 3,822  (207) 8,430 
                      
  
INVESTMENTS:
  
Nuclear plant decommissioning trusts — — 1,158,376 — 1,158,376  — — 1,184 — 1,184 
Investment in associated companies 4,825,221 — —  (4,825,221) —  5,302 — —  (5,302) — 
Other 560 6,639 201 — 7,400  1 9 — — 10 
                      
 4,825,781 6,639 1,158,577  (4,825,221) 1,165,776  5,303 9 1,184  (5,302) 1,194 
                      
  
DEFERRED CHARGES AND OTHER ASSETS:
  
Accumulated deferred income taxes 71,165 402,397 —  (470,205) 3,357 
Accumulated deferred income tax benefits 18 344 —  (362) — 
Customer intangibles 127,420 — — — 127,420  129 — — — 129 
Goodwill 24,248 — — — 24,248  24 — — — 24 
Property taxes — 27,811 22,314 — 50,125  — 16 25 — 41 
Unamortized sale and leaseback costs — — — 61,934 61,934  — 6 — 70 76 
Derivatives 135 — — — 135 
Other 142,039 75,033 7,842  (60,582) 164,332  39 97 7  (68) 75 
                      
 364,872 505,241 30,156  (468,853) 431,416  345 463 32  (360) 480 
                      
 $6,165,227 $6,039,190 $5,431,091 $(5,840,374) $11,795,134  $7,010 $6,326 $5,572 $(6,548) $12,360 
                      
  
LIABILITIES AND CAPITALIZATION
  
 
CURRENT LIABILITIES:
  
Currently payable long-term debt $765 $487,357 $927,772 $(19,102) $1,396,792  $1 $436 $671 $(20) $1,088 
Short-term borrowings-  
Associated companies — 9,642 — — 9,642  453 88 — — 541 
Other 100,000 — — — 100,000  — 1 — — 1 
Accounts payable-  
Associated companies 305,726 244,383 227,328  (305,419) 472,018  665 231 165  (668) 393 
Other 95,287 109,641 — — 204,928  80 111 — — 191 
Accrued taxes 1,821 46,889 56,535  (45,823) 59,422 
Derivatives 242 — — — 242 
Other 253,368 110,964 28,383 38,109 430,824  69 137 46 10 262 
                      
 756,967 1,008,876 1,240,018  (332,235) 2,673,626  1,510 1,004 882  (678) 2,718 
                      
 
CAPITALIZATION:
  
Common stockholder’s equity 3,730,964 2,443,222 2,362,711  (4,805,933) 3,730,964 
Total equity 3,858 2,728 2,556  (5,285) 3,857 
Long-term debt and other long-term obligations 1,518,779 2,053,532 506,533  (1,259,694) 2,819,150  1,483 2,050 706  (1,239) 3,000 
                      
 5,249,743 4,496,754 2,869,244  (6,065,627) 6,550,114  5,341 4,778 3,262  (6,524) 6,857 
                      
  
NONCURRENT LIABILITIES:
  
Deferred gain on sale and leaseback transaction — — — 967,583 967,583  — — — 942 942 
Accumulated deferred income taxes — — 410,095  (410,095) —  — — 504  (288) 216 
Accumulated deferred investment tax credits — 34,050 21,217 — 55,267 
Asset retirement obligations — 26,395 851,127 — 877,522  — 28 847 — 875 
Retirement benefits 36,528 192,251 — — 228,779  50 245 — — 295 
Property taxes — 27,811 22,314 — 50,125 
Lease market valuation liability — 228,119 — — 228,119  — 194 — — 194 
Derivatives 85 — — — 85 
Other 121,989 24,934 17,076 — 163,999  24 77 77 — 178 
                      
 158,517 533,560 1,321,829 557,488 2,571,394  159 544 1,428 654 2,785 
                      
 $6,165,227 $6,039,190 $5,431,091 $(5,840,374) $11,795,134  $7,010 $6,326 $5,572 $(6,548) $12,360 
                      

 

5880

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)
                               
As of December 31, 2009 FES FGCO NGC Eliminations Consolidated 
As of December 31, 2010 FES FGCO NGC Eliminations Consolidated 
 (In thousands)  (In millions) 
ASSETS
  
 
CURRENT ASSETS:
  
Cash and cash equivalents $— $3 $9 $— $12  $— $9 $— $— $9 
Receivables-  
Customers 195,107 — — — 195,107  366 — — — 366 
Associated companies 305,298 175,730 134,841  (297,308) 318,561  333 357 126  (338) 478 
Other 28,394 10,960 12,518 — 51,872  21 56 13 — 90 
Notes receivable from associated companies 416,404 240,836 147,863 — 805,103  34 189 174 — 397 
Materials and supplies, at average cost 17,265 307,079 215,197 — 539,541  41 276 228 — 545 
Derivatives 182 — — — 182 
Prepayments and other 80,025 18,356 9,401 — 107,782  48 10 1 — 59 
                      
 1,042,493 752,964 519,829  (297,308) 2,017,978  1,025 897 542  (338) 2,126 
                      
  
PROPERTY, PLANT AND EQUIPMENT:
  
In service 90,474 5,478,346 5,174,835  (386,023) 10,357,632  96 6,198 5,412  (385) 11,321 
Less — Accumulated provision for depreciation 13,649 2,778,320 1,910,701  (171,512) 4,531,158  17 2,020 2,162  (175) 4,024 
                      
 76,825 2,700,026 3,264,134  (214,511) 5,826,474  79 4,178 3,250  (210) 7,297 
Construction work in progress 6,032 2,049,078 368,336 — 2,423,446  9 520 534 — 1,063 
                      
 82,857 4,749,104 3,632,470  (214,511) 8,249,920  88 4,698 3,784  (210) 8,360 
                      
  
INVESTMENTS:
  
Nuclear plant decommissioning trusts — — 1,088,641 — 1,088,641  — — 1,146 — 1,146 
Investment in associated companies 4,477,602 — —  (4,477,602) —  4,942 — —  (4,942) — 
Other 1,137 21,127 202 — 22,466  — 12 — — 12 
                      
 4,478,739 21,127 1,088,843  (4,477,602) 1,111,107  4,942 12 1,146  (4,942) 1,158 
                      
  
DEFERRED CHARGES AND OTHER ASSETS:
  
Accumulated deferred income taxes 93,379 381,849 —  (388,602) 86,626 
Accumulated deferred income tax benefits 43 412 —  (455) — 
Customer intangibles 16,566 — — — 16,566  134 — — — 134 
Goodwill 24,248 — — — 24,248  24 — — — 24 
Property taxes — 27,811 22,314 — 50,125  — 16 25 — 41 
Unamortized sale and leaseback costs — 16,454 — 56,099 72,553  — 10 — 63 73 
Derivatives 98 — — — 98 
Other 82,845 71,179 18,755  (51,114) 121,665  21 71 14  (58) 48 
                      
 217,038 497,293 41,069  (383,617) 371,783  320 509 39  (450) 418 
                      
 $5,821,127 $6,020,488 $5,282,211 $(5,373,038) $11,750,788  $6,375 $6,116 $5,511 $(5,940) $12,062 
                      
  
LIABILITIES AND CAPITALIZATION
  
 
CURRENT LIABILITIES:
  
Currently payable long-term debt $736 $646,402 $922,429 $(18,640) $1,550,927  $101 $419 $632 $(20) $1,132 
Short-term borrowings-  
Associated companies — 9,237 — — 9,237  — 12 — — 12 
Other 100,000 — — — 100,000 
Accounts payable-  
Associated companies 261,788 170,446 295,045  (261,201) 466,078  351 213 250  (347) 467 
Other 51,722 193,641 — — 245,363  139 102 — — 241 
Accrued taxes 44,213 61,055 22,777  (44,887) 83,158 
Derivatives 266 — — — 266 
Other 173,015 132,314 16,734 36,994 359,057  56 183 46 37 322 
                      
 631,474 1,213,095 1,256,985  (287,734) 2,813,820  913 929 928  (330) 2,440 
                      
  
CAPITALIZATION:
  
Common stockholder’s equity 3,514,571 2,346,515 2,119,488  (4,466,003) 3,514,571  3,788 2,515 2,414  (4,929) 3,788 
Long-term debt and other long-term obligations 1,519,339 1,906,818 554,825  (1,269,330) 2,711,652  1,519 2,119 793  (1,250) 3,181 
                      
 5,033,910 4,253,333 2,674,313  (5,735,333) 6,226,223  5,307 4,634 3,207  (6,179) 6,969 
                      
  
NONCURRENT LIABILITIES:
  
Deferred gain on sale and leaseback transaction — — — 992,869 992,869  — — — 959 959 
Accumulated deferred income taxes — — 342,840  (342,840) —  — — 448  (390) 58 
Accumulated deferred investment tax credits — 36,359 22,037 — 58,396 
Asset retirement obligations — 25,714 895,734 — 921,448  — 27 865 — 892 
Retirement benefits 33,144 170,891 — — 204,035  48 237 — — 285 
Property taxes — 27,811 22,314 — 50,125 
Lease market valuation liability — 262,200 — — 262,200  — 217 — — 217 
Derivatives 81 — — — 81 
Other 122,599 31,085 67,988 — 221,672  26 72 63 — 161 
                      
 155,743 554,060 1,350,913 650,029 2,710,745  155 553 1,376 569 2,653 
                      
 $5,821,127 $6,020,488 $5,282,211 $(5,373,038) $11,750,788  $6,375 $6,116 $5,511 $(5,940) $12,062 
                      

 

5981

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
                                        
For the Nine Months Ended September 30, 2010 FES FGCO NGC Eliminations Consolidated 
For the Six Months Ended June 30, 2011 FES FGCO NGC Eliminations Consolidated 
 (In thousands)  (In millions) 
  
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES
 $(289,503) $402,332 $520,272 $(9,174) $623,927  $(329) $321 $200 $(10) $182 
                      
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New Financing-  
Long-term debt — 249,520 — — 249,520  — 140 107 — 247 
Short-term borrowings, net — 405 — — 405  453 77 — — 530 
Redemptions and Repayments-  
Long-term debt  (599)  (261,965)  (42,949) 9,174  (296,339)  (135)  (192)  (155) 10  (472)
Other  (459)  (237)  (102) —  (798)  (9)  (1)  (1) —  (11)
                      
Net cash used for financing activities  (1,058)  (12,277)  (43,051) 9,174  (47,212)
Net cash provided from (used for) financing activities 309 24  (49) 10 294 
                      
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (5,497)  (417,146)  (378,595) —  (801,238)  (6)  (109)  (219) —  (334)
Proceeds from asset sales — 117,213 — — 117,213 
Sales of investment securities held in trusts — — 1,478,086 — 1,478,086  — — 513 — 513 
Purchases of investment securities held in trusts — —  (1,511,273) —  (1,511,273) — —  (545) —  (545)
Loans from (to) associated companies, net 406,304  (88,625)  (14,224) — 303,455 
Loans to associated companies, net 28  (221) 100 —  (93)
Customer acquisition costs  (110,073) — — —  (110,073)  (2) — — —  (2)
Leasehold improvement payments to associated companies — —  (51,204) —  (51,204)
Other  (173)  (1,499)  (11) —  (1,683) —  (18) — —  (18)
                      
Net cash provided from (used for) investing activities 290,561  (390,057)  (477,221) —  (576,717) 20  (348)  (151) —  (479)
                      
  
Net change in cash and cash equivalents —  (2) — —  (2) —  (3) — —  (3)
Cash and cash equivalents at beginning of period — 3 9 — 12  — 9 — — 9 
                      
Cash and cash equivalents at end of period $— $1 $9 $— $10  $— $6 $— $— $6 
                      

 

6082

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
                     
For the Nine Months Ended September 30, 2009 FES  FGCO  NGC  Eliminations  Consolidated 
  (In thousands) 
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES
 $(37,990) $520,169  $408,364  $(8,732) $881,811 
                
                     
CASH FLOWS FROM FINANCING ACTIVITIES:
                    
New Financing-                    
Long-term debt  1,498,087   524,710   333,965   —   2,356,762 
Short-term borrowings, net  —   —   —   —   — 
Equity contributions from parent  —   100,000   150,000   (250,000)  — 
Redemptions and Repayments-                    
Long-term debt  (1,507)  (258,583)  (366,857)  8,734   (618,213)
Short-term borrowings, net  (901,119)  (257,357)  (6,347)  —   (1,164,823)
Other  (11,583)  (5,261)  (3,160)  (2)  (20,006)
                
Net cash provided from financing activities  583,878   103,509   107,601   (241,268)  553,720 
                
                     
CASH FLOWS FROM INVESTING ACTIVITIES:
                    
Property additions  (2,224)  (439,531)  (400,845)  —   (842,600)
Proceeds from asset sales  —   16,129   —   —   16,129 
Sales of investment securities held in trusts  —   —   2,152,717   —   2,152,717 
Purchases of investment securities held in trusts  —   —   (2,175,135)  —   (2,175,135)
Loans to associated companies, net  (27,054)  (178,746)  (93,041)  —   (298,841)
Investment in subsidiary  (250,000)  —   —   250,000   — 
Other  249   (21,470)  339   —   (20,882)
                
Net cash used for investing activities  (279,029)  (623,618)  (515,965)  250,000   (1,168,612)
                
                     
Net change in cash and cash equivalents  266,859   60   —   —   266,919 
Cash and cash equivalents at beginning of period  —   39   —   —   39 
                
Cash and cash equivalents at end of period $266,859  $99  $—  $—  $266,958 
                
14. INTANGIBLE ASSETS
FES has acquired certain customer contract rights, which were capitalized as intangible assets. These rights allow FES to supply electric generation needs to customers, and the recorded value is being amortized ratably over the term of the related contracts. Net intangible assets of $127 million are included in other assets on FirstEnergy’s Consolidated Balance Sheet as of September 30, 2010.
For the three and nine months ended September 30, 2010, amortization expense was approximately $2 million and $6 million, respectively.
15. IMPAIRMENT OF LONG-LIVED ASSETS
FirstEnergy reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The recoverability of a long-lived asset is measured by comparing its carrying value to the sum of undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is greater than the undiscounted cash flows, an impairment exists and a loss is recognized for the amount by which the carrying value of the long-lived asset exceeds its estimated fair value.
During the quarter ending September 30, 2010, FirstEnergy announced its intention to make operational changes at certain coal-fired FGCO units. The announcement of the operational change indicated a need to evaluate the future recoverability of the carrying value of the assets associated with the affected FGCO units. As a result of the recoverability evaluation, FirstEnergy recorded an impairment of $292 million to other operating expense within continuing operations of its competitive energy services segment for the quarter ending September 30, 2010. This impairment represents a $285 million write down of the carrying value of the assets associated with the affected FGCO units to their estimated fair value and a charge of $7 million for excessive or obsolete inventory identified as a result of the operational changes.
                     
For the Six Months Ended June 30, 2010 FES  FGCO  NGC  Eliminations  Consolidated 
  (In millions) 
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES
 $(223) $163  $287  $(9) $218 
                
                     
CASH FLOWS FROM FINANCING ACTIVITIES:
                    
New Financing-                    
Short-term borrowings, net  —   76   —   —   76 
Redemptions and Repayments-                    
Long-term debt  —   (261)  (43)  9   (295)
Other  (1)  —   —   —   (1)
                
Net cash used for financing activities  (1)  (185)  (43)  9   (220)
                
 
CASH FLOWS FROM INVESTING ACTIVITIES:
                    
Property additions  (4)  (333)  (229)  —   (566)
Proceeds from asset sales  —   116   —   —   116 
Sales of investment securities held in trusts  —   —   957   —   957 
Purchases of investment securities held in trusts  —   —   (979)  —   (979)
Loans to associated companies, net  332   241   58   —   631 
Customer acquisition costs  (105)  —   —   —   (105)
Leasehold improvement payments to associated companies  —   —   (51)  —   (51)
Other  1   (2)  —   —   (1)
                
Net cash provided from (used for) investing activities  224   22   (244)  —   2 
                
 
Net change in cash and cash equivalents  —   —   —   —   — 
Cash and cash equivalents at beginning of period  —   —   —   —   — 
                
Cash and cash equivalents at end of period $—  $—  $—  $—  $— 
                

 

61

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

6283

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 third quarter of 2010Corp. were $179$181 million, or basic and diluted earnings of $0.59$0.43 per share of common stock, compared with $234$265 million, or basic and diluted earnings of $0.77$0.87 per share of common stock in the thirdsecond quarter of 2009. Results in the third quarter of 2010 were adversely affected by an impairment charge for certain coal-fired generation units.2010. Earnings available to FirstEnergy Corp. in the first ninesix months of 20102011 were $599$231 million or basic and diluted earnings of $1.97 ($1.96 diluted)$0.61 per share of common stock, compared with $768$420 million or basic earnings of $2.52$1.38 ($1.37 diluted) per share of common stock ($2.51 diluted) in the first ninesix months of 2009.2010. The principal reasons for the decreases are summarized below.
         
  Three Months  Nine Months 
  Ended  Ended 
Change in Basic Earnings Per Share From Prior Year September 30  September 30 
 
Basic Earnings Per Share — 2009 $0.77  $2.52 
Non-core asset sales/impairments  (0.60)  (1.14)
Trust securities impairments  (0.04)  — 
Regulatory charges  (0.02)  0.45 
Derivative mark-to-market adjustment — 2010  (0.03)  (0.07)
Organizational restructuring — 2009  0.08   0.14 
Merger transaction costs — 2010  (0.04)  (0.09)
Litigation settlements  —   0.04 
Debt call premium — 2009  0.30   0.31 
Income tax resolution — 2009  —   (0.04)
Income tax charge from healthcare legislation — 2010  —   (0.04)
Revenues  0.56   0.72 
Fuel and purchased power  (0.09)  (0.50)
Transmission expense  (0.18)  (0.16)
Amortization of regulatory assets, net  0.17   0.06 
Investment income  (0.26)  (0.23)
Other expenses  (0.03)  — 
       
Basic Earnings Per Share — 2010 $0.59  $1.97 
       
         
  Three Months  Six Months 
Change In Basic Earnings Per Share From Prior Year(1) Ended June 30  Ended June 30 
Basic Earnings Per Share - 2010 $0.87  $1.38 
Non-core asset sales/impairments  (0.01)  (0.04)
Trust securities impairments  0.01   0.02 
Mark-to-market adjustments  (0.10)  (0.02)
Income tax charge from healthcare legislation - 2010  —   0.04 
Regulatory charges - 2011  (0.01)  (0.05)
Regulatory charges - 2010  —   0.08 
Litigation resolution  (0.06)  (0.07)
Merger related costs  (0.02)  (0.31)
Segment operating results -(2)
        
Regulated Distribution  0.02   — 
Competitive Energy Services  (0.15)  (0.24)
Interest expense, net of amounts capitalized  (0.04)  (0.08)
Merger accounting — commodity contracts  (0.08)  (0.12)
Net merger accretion(3)
  0.02   0.06 
Settlement of uncertain tax positions  (0.03)  (0.05)
Other expenses  0.01   0.01 
       
Basic Earnings Per Share - 2011 $0.43  $0.61 
       
(1)Amounts shown are net of income tax effect
(2)Excludes amounts that are shown separately
(3)Excludes merger accounting — commodity contracts, regulatory charges, mark-to-market adjustments and merger-related costs that are shown separately
Pending Merger
As previously disclosed, onOn February 10, 2010,25, 2011, the merger between FirstEnergy entered into anand Allegheny closed. Pursuant to the terms of the Agreement and Plan of Merger subsequently amended on June 4, 2010, (Merger Agreement), withbetween FirstEnergy, Element Merger Sub.Sub, Inc., a Maryland corporation itsand a wholly-owned subsidiary of FirstEnergy (Merger Sub) and Allegheny Energy, Inc., a Maryland corporation (Allegheny Energy). Upon the terms and subject to the conditions set forth in the Merger Agreement,AE, Merger Sub will mergemerged with and into Allegheny EnergyAE with Allegheny EnergyAE continuing as the surviving corporation and a wholly-owned subsidiary of FirstEnergy. Pursuant to the Merger Agreement, upon the closingAs part of the merger, each issued and outstanding share of Allegheny Energy common stock, including grants of restricted common stock, will automatically be converted into the right to receiveAE shareholders received 0.667 of a share of common stock of FirstEnergy, and Allegheny Energy stockholders will own approximately 27% of the combined company. Based on the closing stock prices for both companies on February 10, 2010, Allegheny Energy shareholders would receive a value of $27.65 per share. On July 15, 2010, the most recent practicable date prior to the effectiveness of the Form S-4 registration statement, the exchange ratio represented approximately $25.06 in value for each share of Allegheny Energy common stock. FirstEnergy will also assume all outstanding Allegheny Energy debt.
FirstEnergy shareholders and Allegheny Energy stockholders approved the various proposals related to the merger in separate special shareholder meetings on September 14, 2010. FirstEnergy shareholders approved the issuance of shares of FirstEnergy common stock for each AE share outstanding as of the merger completion date and all outstanding AE equity-based employee compensation awards were converted into FirstEnergy equity-based awards on the same basis.
In connection with the merger, FirstEnergy recorded approximately $7 million of merger transaction costs during each of the second quarter of 2011 and 2010, and approximately $89 million and $21 million of merger transaction costs during the first six months of 2011 and 2010, respectively. These costs are included in “Other operating expenses” in the Consolidated Statements of Income. FirstEnergy’s consolidated financial statements include Allegheny’s results of operations and financial position effective February 25, 2011. In addition, during the three months ended June 30, 2011, $10 million of merger integration costs and $8 million of charges from merger settlements approved by regulatory agencies were recognized. In the other transactions contemplatedfirst six months of 2011, $85 million of merger integration costs and $32 million of charges from merger settlements approved by regulatory agencies were recognized. Charges resulting from merger settlements are not expected to be material in future periods.
FirstEnergy expects to achieve 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 approved2011 merger benefits target resulting from the merger with total votes representing 80%Allegheny. Through June 2011, FirstEnergy has taken actions and completed savings initiatives that will allow the company to capture merger benefits of Allegheny Energy’s outstanding shares, of which 99% voted in favorapproximately $132 million pre-tax on an annual basis, or 63% of the merger.$210 million annual target. The $132 million realized from savings initiatives completed through June, along with the impact of initiatives still underway, will be reflected in earnings throughout 2011.

 

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Pursuant to the Merger Agreement, completion of the merger remains conditioned upon, among other things, the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and approval by FERC, the MDPSC, the PPUC and the PSCWV. The Merger Agreement also contains certain termination rights for both FirstEnergy and Allegheny Energy, and further provides for the payment of fees and expenses upon termination under specified circumstances.
FirstEnergy and Allegheny Energy currently anticipate completing the merger in the first half of 2011. Although FirstEnergy and Allegheny Energy believe that they will receive the remaining required authorizations, approvals and consents to complete the merger, there can be no assurance as to the timing of these authorizations, approvals and consents or as to FirstEnergy’s and Allegheny Energy’s ultimate ability to obtain such authorizations, consents or approvals (or any additional authorizations, approvals or consents which may otherwise become necessary) or that such authorizations, approvals or consents will be obtained on terms and subject to conditions satisfactory to Allegheny Energy and FirstEnergy. Further information concerning the proposed merger is included in the Registration Statement filed by FirstEnergy with the SEC in connection with the merger.
FirstEnergy incurred approximately $14 million ($11 million after tax) of merger transaction costs in the third quarter and approximately $35 million ($26 million after tax) of merger transaction costs in the first nine months of 2010. These costs are charged to expense as incurred.Operational Matters
FERCTrAIL
On May 11, 2010, FirstEnergy19, 2011, TrAIL’s 500-kV transmission line, spanning more than 150 miles from southwestern Pennsylvania through West Virginia to northern Virginia, was completed and Allegheny Energy filedenergized.
ATSI Integrated into PJM
On June 1, 2011, ATSI successfully integrated into PJM. With this transition, all of FirstEnergy’s generation, transmission and distribution facilities are now in PJM.
Perry Refueling
On June 7, 2011, the Perry Plant returned to service following a scheduled shutdown for refueling and maintenance which began on April 18, 2011. During the outage, 248 of the 748 fuel assemblies were replaced and safety inspections were successfully conducted. Additionally, numerous preventative maintenance activities and improvement projects were completed that we believe will result in continued safe and reliable operations, including replacement of several control rod blades, rewind of the generator, and routine work on more than 150 valves, pumps and motors.
New Nuclear Emergency Operations Facilities
In June 2011, FENOC broke ground for new Emergency Operations Facilities for the Beaver Valley Power Station and Perry Nuclear Power Plant. Each of the 12,000 square-foot facilities will house activities related to maintaining public health and safety during the unlikely event of an application with FERCemergency at the plant and allow for approval of their proposed merger. Underimproved coordination between the Federal Power Act, FERC has 180 days to rule on a completed merger application. FirstEnergyplant, state and Allegheny Energy submitted additional information regarding the merger application on June 21, 2010 in response to a request by FERC. Interventions and protests were filed with FERC on July 12, 2010. On July 27, 2010, FirstEnergy filed additional information with FERC in response to the interventions. FERClocal emergency management agencies. FENOC is expected to complete its reviewbreak ground for a similar facility for the Davis-Besse Nuclear Power Station in sufficient time to meet the anticipated merger closing schedule in the first half ofAugust 2011.
State Regulatory Merger FilingsFremont Energy Center
On September 9, 2010,July 28, 2011, FirstEnergy closed on the VSCC approved a petitionpreviously announced sale of Fremont Energy Center to American Municipal Power, Inc. for the FirstEnergy-Allegheny Energy merger.$510 million based on 685 MW of output. The purchase price can be incrementally increased, not to exceed an additional $16 million, to reflect additional transmission export capacity up to 707 MW.
Pennsylvania Settlement
On October 25, 2010, FirstEnergy and Allegheny Energy filed a comprehensive settlement with the PPUC that addresses issues raised by 18 of the parties to the merger. The filing includes additional commitments related to employment levels, including a five-year commitment to maintain at least 800 jobs in Greensburg and Westmoreland County for the first year after the merger close, 675 jobs for the following 12 months, 650 jobs for the next year and 600 jobs for each of the next two years. The settlement also provides nearly $11 million over a three year time frame in distribution rate credits for West Penn Power customers, a distribution rate freeze for FirstEnergy’s current Pennsylvania utility customers and support for renewable and sustainable energy and customer choice. The settlement is subject to approval by the PPUC, and does not resolve issues raised by parties who did not join in the settlement.
Hart-Scott-Rodino (HSR) Act Filings
On May 25, 2010, FirstEnergy and Allegheny Energy made HSR filings with the DOJ and Federal Trade Commission. On June 24, 2010, FirstEnergy and Allegheny Energy each received a request for additional information from the DOJ. FirstEnergy and Allegheny Energy continue to cooperate with the DOJ and expect DOJ to complete its review in sufficient time to meet the anticipated merger closing schedule in the first half of 2011.
Financial Matters
Financing ActivitiesOn April 29, 2011, Met-Ed redeemed $13.69 million of pollution control revenue bonds at par value.
On August 20, 2010, FES completed the remarketing ofMay 4, 2011, AE terminated its $250 million credit facility due to other available funding sources following completion of PCRBs. Of the $250merger with FirstEnergy.
On May 31, 2011, JCP&L and Met-Ed repurchased $500 million $235and $150 million, respectively, of their equity from FirstEnergy to maintain an appropriate capital structure.
On June 1, 2011, FGCO repurchased $40 million of PCRBspollution control revenue bonds and is holding those bonds for future remarketing or refinancing.
On June 17, 2011, FirstEnergy and certain of its subsidiaries entered into two 5-year revolving credit facilities with a total borrowing capacity of $4.5 billion. These facilities consist of a $2 billion revolving credit facility for FirstEnergy and its regulated entities and a $2.5 billion revolving credit facility for FES and AE Supply. Prior separate facilities ($2.75 billion at FirstEnergy, $1 billion at AE Supply, $110 million at MP, $150 million at PE and $200 million at WP) were converted from a variable interest rateterminated.
On July 29, 2011, FGCO and NGC provided notice to a fixed interest rate. The remaining $15the trustee for $158.1 million and $158.9 million, respectively, of PCRBs continueof their election to bear a fixed interest rate. The interest rate conversion minimizes financial risk by converting the long-term debt into a fixed rate and, asterminate applicable supporting LOCs. As a result, reducing exposure to variable interest rates over the short-term. These remarketings included two series: $235 million ofthese PCRBs that now bear a per-annum rate of 2.25% and are subject to mandatory purchase on June 3, 2013;September 1, 2011. Subject to market conditions and $15other considerations, FGCO and NGC currently expect to hold the bonds for future remarketing or refinancing. Also, approximately $28.5 million and $98.9 million aggregate principal amount of PCRBs that now bear a per-annum rateFMBs previously delivered to certain of 1.5%the LOC providers by FGCO and are subject toNGC, respectively, will be cancelled in connection with the mandatory purchase on June 1, 2011.purchases.
Regulatory Matters
NYSEG Ruling
On October 1, 2010, FES completedJuly 11, 2011, FirstEnergy was found to be a potentially responsible party under CERCLA indirectly liable for a portion of past and future clean-up costs at certain legacy MGP sites in New York. As a result, FirstEnergy recognized additional expense of $29 million during the refinancing and remarketingsecond quarter of six series of PCRBs totaling $313 million. These series of PCRBs were converted from a variable interest rate2011; $30 million had previously been reserved prior to a fixed long term interest rate of 3.375% per-annum and are subject to mandatory purchase on July 1, 2015.
On October 22, 2010, Signal Peak and Global Rail entered into a $350 million syndicated two-year senior secured term loan facility among the two limited liability companies that comprise Signal Peak and Global Rail, as borrowers, Sovereign Bank, CoBank, Credit Agricole, U.S. Bank, BBVA Compass, Royal Bank of Canada, Fifth Third, Comerica Bank, CIBC Inc. and First Merit banks, as lenders, and Union Bank, N.A. as lender, administrative agent, collateral agent and syndication agent. FirstEnergy, together with WMB Loan Ventures LLC and WMB Loan Ventures II LLC, the entities that share ownership with FEV in the borrowers, have provided a guaranty of the borrowers’ obligations under the facility. The loan proceeds were used to repay $258 million of notes payable to FirstEnergy, including $9 million of interest and $63 million of bank loans that were scheduled to mature on November 16, 2010. Additional proceeds will be used for general company purposes, including an $11 million repayment of a third-party seller’s note maturing October 29, 2010.2011.

 

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Operational Matters
Plant Operational ChangesMarginal transmission loss recovery
On August 12,March 3, 2010, FGCO announced that it would be making operational changesthe PPUC issued an order denying Met-Ed and Penelec the ability to some of its smaller coal-fired unitsrecover marginal transmission losses through the transmission service charge riders in responsetheir respective tariffs which applies to the continued slow economyperiods including June 1, 2008 through December 31, 2010. Subsequently, Met-Ed and lower demandPenelec filed a Petition for electricity and uncertainty related to proposed new federal environmental regulations. The units affected are Bay Shore units 2-4, Eastlake units 1-4,Review with the Lake Shore Plant andCommonwealth Court of Pennsylvania (Commonwealth Court) appealing the Ashtabula Plant, which together total 1,620 MW of capacity. During the period beginning September 2010 through AugustPPUC’s order. On June 14, 2011, the affected units will operateCommonwealth Court affirmed the PPUC’s decision that marginal transmission losses are not recoverable as transmission costs. On July 13, 2011, Met-Ed and Penelec filed a federal complaint with minimum three-day noticethe United States District Court for the Eastern District of Pennsylvania and in responseon the following day, filed a Petition for Allowance of Appeal to consumer demand. Beginning in Septemberthe Pennsylvania Supreme Court. Met-Ed and Penelec believe the Commonwealth Court’s decision contradicts federal law and is inconsistent with prior PPUC and court decisions and therefore expect to fully recover the related regulatory assets ($189 million for Met-Ed and $65 million for Penelec). In January 2011 and continuing for approximately 1829 months, pursuant to a related PPUC order, Met-Ed and Penelec began crediting customers for the Bay Shore and Eastlake units (1,131 MW) will onlyamounts at issue pending outcome of the court appeals.
FIRSTENERGY’S BUSINESS
With the completion of the Allegheny merger in the first quarter of 2011, FirstEnergy reorganized its management structure, which resulted in changes to its operating segments to be available during summer and winter months, and Ashtabula and Lake Shore will be temporarily idled (489 MW). As a result,consistent with the company recognized an impairment of $292 million for these assets. Together, these units have a generating capacity of 1,620MW, andmanner in 2009 they produced approximately 6.8% of FGCO’s totalwhich management views the business. The new structure supports the combined company’s primary operations — distribution, transmission, generation output. The proposed changes are subject to review by MISO, PJM and the independent market monitorsmarketing and sale of its products. The external segment reporting is consistent with the internal financial reporting used by FirstEnergy’s chief executive officer (its chief operating decision maker) to ensure that there is no negative impact on system reliability.regularly assess the performance of the business and allocate resources. FirstEnergy now has three reportable operating segments — Regulated Distribution, Regulated Independent Transmission and Competitive Energy Services.
Davis-Besse License Renewal
On August 30, 2010, FENOC submitted an applicationPrior to the NRCchange in composition of business segments, FirstEnergy’s business was comprised of two reportable operating segments. The Energy Delivery Services segment included FirstEnergy’s then eight existing utility operating companies that transmit and distribute electricity to customers and purchase power to serve their POLR and default service requirements. The Competitive Energy Services segment was comprised of FES, which supplies electric power to end-use customers through retail and wholesale arrangements. The “Other” segment consisted of corporate items and other businesses that were below the quantifiable threshold for renewalseparate disclosure. Disclosures for FirstEnergy’s operating segments for 2010 have been reclassified to conform to the current presentation.
The changes in FirstEnergy’s reportable segments during the first quarter of 2011 consisted primarily of the Davis-Besse operating license. By a letter dated October 18, 2010, the NRC determined that the Davis-Besse license renewal applicationfollowing:
Energy Delivery Services was complete and acceptable for docketing and further review. Davis-Besse currently is licensed until 2017; if approved, the renewal would extend operations for an additional 20 years, until 2037.
Fremont Energy Center Construction
During the third quarter, FGCO re-evaluated the schedule for completing the Fremont Plant (707 MW) due to current market conditionsrenamed Regulated Distribution and the extensionoperations of the tax incentives included in the Small Business legislation through 2011. As a result, FGCO is extending the plant’s completion beyond 2010 to reduce overtime labor costMP, PE and outside contractor spend for the remainder of the project. We expect the extension of the completion schedule to add $33 million to the 2011 capital budget.
Regulatory Matters — General
DOE Smart Grid Grants and Smart Meter Implementation
On June 3, 2010, FirstEnergy received DOE’s grants totaling $57.4 million, awardedWP, which were acquired as part of the American Recoverymerger with Allegheny, and Reinvestment Act, to be used to introduce smart grid technologies in targeted areas of Pennsylvania, Ohio and New Jersey. The DOE grants represent 50% of the funding for the $114.9 million FE plans to invest in smart grid technologies. The PPUC and the NJBPU previously approvedcertain regulatory asset recovery for the applicable utilities portion of smart grid costs, and FirstEnergy has begun implementing smart grid programs in Pennsylvania and New Jersey. Implementation of the program in Ohio is underway following clarification by the PUCO in its entry on rehearing issued August 25, 2010 that the Ohio Companies are entitled to cost recovery for any costs not covered by the DOE grant.
Regulatory Matters — Ohio
New Ohio ESP
On August 25, 2010, the PUCO adopted a Combined Stipulation in the second ESP for the Ohio Companies’ effective June 1, 2011 through May 31, 2014. Under the new ESP, base distribution rates will remain unchanged during the term of the ESP, except in cases of emergencies, subject to riders and other changes provided in the Ohio Companies’ tariffs. Generation rates for each annual delivery period (June 1 to May 31) through May 31, 2014, will be determined through a CBP to be conducted every October and January for generation service.
The ESP provides for recovery of certain costs related to FirstEnergy’s integration into PJM, which is scheduled for June 1, 2011. However, the Ohio Companies will not seek recovery for any MISO exit fees, PJM integration costs, or legacy regional transmission expansion plan costs billed by PJM for the longer of a five year period from June 1, 2011 through May 31, 2016 or when the amount of costs avoided by customers for certain types of products totals $360 million dependent on the outcome of certain PJM proceedings for projects approved prior to June 1, 2011.
The new ESP also establishes a Delivery Capital Recovery Rider effective January 1, 2012, through May 31, 2014, which provides for recovery of property taxes, commercial activity tax and associated income taxes and for the opportunity to earn a return on and of plant in service associated with distribution, subtransmission and general and intangible plant that was notmechanisms formerly included in the Ohio Companies’ rate base“Other” segment, were placed into this segment.
A new Regulated Independent Transmission segment was created consisting of ATSI, and the operations of TrAIL Company and FirstEnergy’s interest in PATH; TrAIL and PATH were acquired as determinedpart of the merger with Allegheny. The transmission assets and operations of JCP&L, Met-Ed, Penelec, MP, PE and WP remain within the Regulated Distribution segment.
AE Supply, an operator of generation facilities that was acquired as part of the merger with Allegheny, was placed into the Competitive Energy Services segment.
Financial information for each of FirstEnergy’s reportable segments is presented in the 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 milliontable below, which includes financial results for the first five months of 2014.Allegheny subsidiaries beginning February 25, 2011. FES and the Utilities do not have separate reportable operating segments.
Ohio Generation Auction
On October 20, 2010, the Ohio Companies conducted a CBP to procure generation for customers who choose not to shop with an alternative supplier for delivery beginning June 1, 2011 through May 31, 2014. The auction consisted of one, two and three-year products. Fifty tranches in total were acquired through this auction. Seventeen tranches of the one-year product were acquired at a clearing price of $54.55 per MWh; seventeen tranches of the two-year product were acquired at a clearing price of $54.10 per MWh; and sixteen tranches of the three-year product were acquired at a clearing price of $56.58 per MWh. There were ten registered bidders that participated in the auction, with four bidders winning tranches in the auction. The auction consisted of twelve rounds. On October 22, 2010, the PUCO accepted the results of the auction. The next auction is scheduled for January 2011.

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Regulatory Matters — Pennsylvania
Met-Ed and Penelec Default Service Plan
On October 20, 2010, the PPUC approved the results of the final of four auctions held to procure the default service requirements for Met-Ed and Penelec customers who choose not to shop with an alternative supplier. For the five-month period of January 1, 2011 to May 31, 2011, the tranche-weighted average prices ($/MWh) for Met-Ed’s residential and commercial classes were $67.10 and $68.28, respectively; Penelec’s tranche-weighted average prices were $55.76 and $58.24 for its residential and commercial classes, respectively. The October 2010 auction is the second of four auctions to procure commercial default service requirements for the 12-month period of June 1, 2011 to May 31, 2012 and residential requirements for the 24-month period of June 1, 2011 to May 31, 2013. For Met-Ed and Penelec commercial customers the tranche-weighted average price ($/MWh) was $63.97 and $54.33, respectively, and for residential customers the tranche-weighted average price was $66.66 and $55.74, respectively. In addition, the October 2010 auction procured supply for Met-Ed and Penelec industrial customers choosing the Fixed Price Service. For Met-Ed and Penelec, the average 12-month price ($/MWh) was $95.00 and $83.73, respectively. The remaining two auctions for these products will be conducted in January 2011 and March 2011.
On October 20, 2010, the PPUC also approved the default service RFP for the Residential Fixed Block On-Peak and Off-Peak energy products. For Penelec, the average price ($/MWh) for On-Peak and Off-Peak was $47.25 and $38.62, respectively. For Met-Ed, the average price ($/MWh) for On-Peak and Off-Peak was $55.07 and $40.81, respectively.
Regulatory Matters — FERC
MISO Multi-Value Project Rule Proposal
On September 10, 2010, FirstEnergy filed a protest to MISO’s MVP proposal. FirstEnergy believes that MISO’s proposal to allocate costs of MVP projects across the entire MISO footprint does not align with the established rule that cost allocation is to be based on cost causation (the “beneficiary pays” approach) among other objections. FirstEnergy also argued that, in light of progress to date in the ATSI move to PJM, it would be unjust and unreasonable to allocate any MVP costs to the ATSI zone, or to ATSI. FirstEnergy is unable to predict the outcome of this matter.
FIRSTENERGY’S BUSINESS
FirstEnergy is a diversified energy company headquartered in Akron, Ohio, that operates primarily through two core business segments (see Results of Operations).
Energy Delivery Servicestransmits andRegulated Distribution segment distributes electricity through our eightFirstEnergy’s ten utility operating companies, serving 4.5approximately 6 million customers within 36,10067,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New JerseyYork, and purchases power for its POLR, SOS and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also includes the transmission operations of JCP&L, Met-Ed, Penelec, WP, MP and PE and the regulated electric generation facilities in West Virginia and New Jersey. ItsJersey which MP and JCP&L, respectively, own or contractually control.
The Regulated Distribution segment’s revenues are primarily derived from the delivery of electricity within ourFirstEnergy’s service areas, cost recovery of regulatory assets and the sale of electric generation service to retail customers who have not selected an alternative supplier (default(POLR, SOS or default service) in its Ohio, Pennsylvania andMaryland, New Jersey, Ohio and Pennsylvania franchise areas. Its results reflect the commodity costs of securing electric generation from FES and AE Supply and from non-affiliated power suppliers and the deferral and amortization of certain fuel costs.

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The Regulated Independent Transmission segment transmits electricity through transmission lines. Its revenues are primarily derived from the formula rate recovery of costs and a return on investment for capital expenditures in connection with TrAIL, PATH and other projects and revenues from providing transmission services to electric energy providers, power marketers and receiving transmission-related revenues from operation of a portion of the FirstEnergy transmission system. Its results reflect the net PJM and MISO transmission expenses related to the delivery of the respective generation loads andloads. On June 1, 2011, the deferral and amortizationATSI transmission assets previously dedicated to MISO were integrated into the PJM market. All of certain fuel costs.
FirstEnergy’s assets now reside in one RTO.
The Competitive Energy Services segment, through FES, supplies electric power to end-use customers through retail and wholesale arrangements, including associated company power sales to meet all or a portion of the POLR and default service requirements of ourFirstEnergy’s Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Maryland, Michigan and New Jersey. FES purchases the entire output of the 18 generating facilities which it owns and operates through its FGCO subsidiary (fossil and hydroelectric generating facilities) and owns, through its NGC subsidiary, FirstEnergy’s nuclear generating facilities. FENOC, a separate subsidiary of FirstEnergy, operates and maintains NGC’s nuclear generating facilities as well as the output relating to leasehold interests of OE and TE in certain of those facilities that are subject to sale and leaseback arrangements with non-affiliates, pursuant to full output, cost-of-service PSAs.
The Competitive Energy Services segment also includes Allegheny’s unregulated electric generation operations, including AE Supply and AE Supply’s interest in AGC. AE Supply owns, operates and controls the electric generation capacity of its 18 facilities. AGC owns and sells generation capacity to AE Supply and MP, which own approximately 59% and 41% of AGC, respectively. AGC’s sole asset is a 40% undivided interest in the Bath County, Virginia pumped-storage hydroelectric generation facility and its connecting transmission facilities. All of AGC’s revenues are derived from sales of its 1,109 MW share of generation capacity from the Bath County generation facility to AE Supply and MP.
This business segment controls approximately 14,000 MW20,000 MWs of capacity and also purchases electricity to meet sales obligations. The segment’s net income is primarily derived from affiliated and non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO (prior to June 1, 2011) to deliver energy to the segment’s customers.

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The Other and Reconciling Adjustments segment contains corporate items and other businesses that are below the quantifiable threshold for separate disclosure as a reportable segment as well as reconciling adjustments for the elimination of intersegment transactions.
RESULTS OF OPERATIONS
The financial results discussed below include revenues and expenses from transactions among FirstEnergy’s business segments. Results from the pre-merged companies have been segregated from the Allegheny companies for variance reporting and analysis. A reconciliation of segment financial results is provided in Note 1213 to the consolidated financial statements. Earnings available to FirstEnergy by major business segment were as follows:
                                                
 Three Months Ended Nine Months Ended  Three Months Ended Six Months Ended 
 September 30 September 30  June 30 June 30 
 Increase Increase  Increase Increase 
 2010 2009 (Decrease) 2010 2009 (Decrease)  2011 2010 (Decrease) 2011 2010 (Decrease) 
 (In millions, except per share data)  (In millions, except per share data) 
Earnings (Loss) By Business Segment:
  
Energy delivery services $224 $148 $76 $481 $285 $196 
Competitive energy services  (27) 183  (210) 174 614  (440)
Regulated Distribution $184 $132 $52 $280 $235 $45 
Competitive Energy Services 12 121  (109) 17 190  (173)
Regulated Independent Transmission 31 11 20 44 23 21 
Other and reconciling adjustments*  (18)  (97) 79  (56)  (131) 75   (46) 1  (47)  (110)  (28)  (82)
                          
Total $179 $234 $(55) $599 $768 $(169)
Earnings available to FirstEnergy Corp. $181 $265 $(84) $231 $420 $(189)
                          
  
Basic Earnings Per Share
 $0.59 $0.77 $(0.18) $1.97 $2.52 $(0.55) $0.43 $0.87 $(0.44) $0.61 $1.38 $(0.77)
Diluted Earnings Per Share
 $0.59 $0.77 $(0.18) $1.96 $2.51 $(0.55) $0.43 $0.87 $(0.44) $0.61 $1.37 $(0.76)
* Consists primarily of interest expense related to holding company debt, corporate support services revenues and expenses, noncontrolling interests and the elimination of intersegment transactions.

87

Summary of Results of Operations — ThirdSecond Quarter 20102011 Compared with ThirdSecond Quarter 20092010
Financial results for FirstEnergy’s major business segments in the thirdsecond quarter of 20102011 and 20092010 were as follows:
                                    
 Energy Competitive Other and    Competitive Regulated Other and   
 Delivery Energy Reconciling FirstEnergy  Regulated Energy Independent Reconciling FirstEnergy 
Third Quarter 2010 Financial Results Services Services Adjustments Consolidated 
Second Quarter 2011 Financial Results Distribution Services Transmission Adjustments Consolidated 
 (In millions)  (In millions) 
Revenues:  
External  
Electric $2,609 $905 $— $3,514  $2,352 $1,394 $— $— $3,746 
Other 148 52  (21) 179  133 101 105  (37) 302 
Internal 60 599  (659) —  — 318 —  (306) 12 
                    
Total Revenues 2,817 1,556  (680) 3,693  2,485 1,813 105  (343) 4,060 
                    
  
Expenses:  
Fuel — 401  (1) 400  73 562 — — 635 
Purchased power 1,473 470  (659) 1,284  1,144 382 —  (306) 1,220 
Other operating expenses 422 347  (31) 738  438 640 19 8 1,105 
Provision for depreciation 111 62 9 182  153 107 15 7 282 
Amortization of regulatory assets 176 — — 176  87 — 3 — 90 
Deferral of new regulatory assets — — — — 
Impairment of long lived assets — 292 — 292 
General taxes 174 26 6 206  180 51 8 3 242 
                    
Total Expenses 2,356 1,598  (676) 3,278  2,075 1,742 45  (288) 3,574 
                    
  
Operating Income 461  (42)  (4) 415  410 71 60  (55) 486 
                    
Other Income (Expense):  
Investment income 23 28  (5) 46  27 15 —  (11) 31 
Interest expense  (125)  (53)  (30)  (208)  (148)  (79)  (12)  (26)  (265)
Capitalized interest 2 23 16 41  3 12 1 4 20 
                    
Total Other Expense  (100)  (2)  (19)  (121)  (118)  (52)  (11)  (33)  (214)
                    
  
Income Before Income Taxes 361  (44)  (23) 294  292 19 49  (88) 272 
Income taxes 137  (17)  (1) 119  108 7 18  (32) 101 
                    
Net Income (Loss) 224  (27)  (22) 175  184 12 31  (56) 171 
Loss attributable to noncontrolling interest — —  (4)  (4) — — —  (10)  (10)
                    
Earnings available to FirstEnergy Corp. $224 $(27) $(18) $179 
Earnings (loss) available to FirstEnergy Corp. $184 $12 $31 $(46) $181 
                    

 

6788

                 
  Energy  Competitive  Other and    
  Delivery  Energy  Reconciling  FirstEnergy 
Third Quarter 2009 Financial Results Services  Services  Adjustments  Consolidated 
  (In millions) 
Revenues:                
External                
Electric $2,804  $444  $—  $3,248 
Other  138   46   (24)  160 
Internal  —   617   (617)  — 
             
Total Revenues  2,942   1,107   (641)  3,408 
             
                 
Expenses:                
Fuel  —   302   —   302 
Purchased power  1,725   205   (617)  1,313 
Other operating expenses  366   331   (32)  665 
Provision for depreciation  112   69   7   188 
Amortization of regulatory assets  261   —   —   261 
Deferral of new regulatory assets  —   —   —   — 
Impairment of long lived assets  —   —   —   — 
General taxes  162   27   3   192 
             
Total Expenses  2,626   934   (639)  2,921 
             
                 
Operating Income  316   173   (2)  487 
             
Other Income (Expense):                
Investment income  46   159   (14)  191 
Interest expense  (116)  (46)  (193)  (355)
Capitalized interest  1   18   16   35 
             
Total Other Expense  (69)  131   (191)  (129)
             
                 
Income Before Income Taxes  247   304   (193)  358 
Income taxes  99   121   (92)  128 
             
Net Income (Loss)  148   183   (101)  230 
Loss attributable to noncontrolling interest  —   —   (4)  (4)
             
Earnings available to FirstEnergy Corp. $148  $183  $(97) $234 
             
                                    
Changes Between Third Quarter 2010 and Energy Competitive Other and   
Third Quarter 2009 Financial Results Delivery Energy Reconciling FirstEnergy 
Increase (Decrease) Services Services Adjustments Consolidated 
 Competitive Regulated Other and   
 Regulated Energy Independent Reconciling FirstEnergy 
Second Quarter 2010 Financial Results Distribution Services Transmission Adjustments Consolidated 
 (In millions)  (In millions) 
Revenues:  
External  
Electric $(195) $461 $— $266  $2,243 $739 $— $— $2,982 
Other 10 6 3 19  71 56 59  (29) 157 
Internal 60  (18)  (42) —  19 539 —  (558) — 
                    
Total Revenues  (125) 449  (39) 285  2,333 1,334 59  (587) 3,139 
                    
  
Expenses:  
Fuel — 99  (1) 98  — 350 — — 350 
Purchased power  (252) 265  (42)  (29) 1,291 330 —  (558) 1,063 
Other operating expenses 56 16 1 73  331 340 16  (14) 673 
Provision for depreciation  (1)  (7) 2  (6) 106 71 10 3 190 
Amortization of regulatory assets  (85) — —  (85) 158 — 3 — 161 
Deferral of new regulatory assets — — — — 
Impairment of long lived assets — 292 — 292 
General taxes 12  (1) 3 14  138 27 7 4 176 
                    
Total Expenses  (270) 664  (37) 357  2,024 1,118 36  (565) 2,613 
                    
  
Operating Income 145  (215)  (2)  (72) 309 216 23  (22) 526 
                    
Other Income (Expense):  
Investment income  (23)  (131) 9  (145) 28 13 —  (10) 31 
Interest expense  (9)  (7) 163 147   (125)  (57)  (6)  (19)  (207)
Capitalized interest 1 5 — 6  1 24 1 14 40 
                    
Total Other Expense  (31)  (133) 172 8   (96)  (20)  (5)  (15)  (136)
                    
  
Income Before Income Taxes 114  (348) 170  (64) 213 196 18  (37) 390 
Income taxes 38  (138) 91  (9) 81 75 7  (29) 134 
                    
Net Income (Loss) 76  (210) 79  (55) 132 121 11  (8) 256 
Loss attributable to noncontrolling interest — — — —  — — —  (9)  (9)
                    
Earnings available to FirstEnergy Corp. $76 $(210) $79 $(55) $132 $121 $11 $1 $265 
                    

 

6889

                     
Changes Between Second Quarter 2011     Competitive  Regulated  Other and    
and Second Quarter 2010 Financial Regulated  Energy  Independent  Reconciling  FirstEnergy 
Results Increase (Decrease) Distribution  Services  Transmission  Adjustment  Consolidated 
  (In millions) 
                     
Revenues:                    
External                    
Electric $109  $655  $—  $—  $764 
Other  62   45   46   (8)  145 
Internal  (19)  (221)  —   252   12 
                
Total Revenues  152   479   46   244   921 
                
                     
Expenses:                    
Fuel  73   212   —   —   285 
Purchased power  (147)  52   —   252   157 
Other operating expenses  107   300   3   22   432 
Provision for depreciation  47   36   5   4   92 
Amortization of regulatory assets  (71)  —   —   —   (71)
General taxes  42   24   1   (1)  66 
                
Total Expenses  51   624   9   277   961 
                
                     
Operating Income  101   (145)  37   (33)  (40)
                
Other Income (Expense):                    
Investment income  (1)  2   —   (1)  — 
Interest expense  (23)  (22)  (6)  (7)  (58)
Capitalized interest  2   (12)  —   (10)  (20)
                
Total Other Expense  (22)  (32)  (6)  (18)  (78)
                
                     
Income Before Income Taxes  79   (177)  31   (51)  (118)
Income taxes  27   (68)  11   (3)  (33)
                
Net Income  52   (109)  20   (48)  (85)
Loss attributable to noncontrolling interest  —   —   —   (1)  (1)
                
Earnings available to FirstEnergy Corp. $52  $(109) $20  $(47) $(84)
                
Energy Delivery ServicesRegulated Distribution — ThirdSecond Quarter 2011 Compared with Second Quarter 2010 Compared with Third Quarter 2009
Net income increased by $76$52 million in the thirdsecond quarter of 2011 compared to the second quarter of 2010 compared to the third quarter of 2009, primarily due to higher distribution revenues. Lower generation revenues wereearnings from the Allegheny companies and increased operating margins from the pre-merger companies as a result of reduced purchased power costs, partially offset by lower purchased power expenses.reduced revenues.

90

Revenues —-
The decreaseincrease in total revenues resulted from the following sources:
                        
 Three Months    Three Months   
 Ended September 30 Increase  Ended June 30 Increase 
Revenues by Type of Service 2010 2009 (Decrease)  2011 2010 (Decrease) 
 (In millions)  (In millions) 
Pre-merger companies: 
Distribution services $1,041 $915 $126  $810 $851 $(41)
              
Generation sales:  
Retail 1,266 1,551  (285) 747 1,097  (350)
Wholesale 231 195 36  104 180  (76)
              
Total generation sales 1,497 1,746  (249) 851 1,277  (426)
              
Transmission 223 232  (9) 51 141  (90)
Other 56 49 7  66 64 2 
              
Total pre-merger companies 1,778 2,333  (555)
       
Allegheny companies 707 — 707 
       
Total Revenues $2,817 $2,942 $(125) $2,485 $2,333 $152 
              
The increasedecrease in distribution service revenues reflected an $88 million increasefor the pre-merger companies reflects lower transition revenues due to higher sales volumes and a $38 million increase due to athe completion of transition cost recovery for CEI in December 2010, partially offset by increased rates associated with the recovery of deferred distribution costs. Distribution deliveries (excluding the Allegheny companies) decreased by 1.1% in the second quarter of 2011 from the second quarter of 2010. The 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%
             
          Increase 
Electric Distribution KWH Deliveries 2011  2010  (Decrease) 
  (in thousands)     
Pre-merger companies:            
Residential  8,623   8,663   (0.5)%
Commercial  7,926   8,121   (2.4)%
Industrial  8,798   8,846   (0.5)%
Other  126   132   (4.5)%
          
Total pre-merger companies  25,473   25,762   (1.1)%
          
Allegheny companies  9,527   —   — 
          
Total Electric Distribution KWH Deliveries  35,000   25,762   35.9%
          
HigherLower deliveries to residential and commercial customers reflected increaseddecreased weather-related usage in the thirdsecond quarter of 2010,2011 as cooling degree days increaseddecreased by 60%17.3% from the same period in 2009. The increase in distribution deliveries to industrial customers was primarily due to recovering2010, and soft economic conditions in FirstEnergy’s service territory compared toaffecting the third quarter of 2009.commercial sector. In the industrial sector, KWH deliveries increaseddecreased by 4% to major automotive customers, (14%)partially offset by increased deliveries to steel and electrical equipment customers of 11% and 15%, 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.respectively.
The following table summarizes the price and volume factors contributing to the $249$426 million decrease in generation revenues for the pre-merger companies in the thirdsecond quarter of 20102011 compared to the thirdsecond quarter of 2009:2010:
        
 Increase  Increase 
Source of Change in Generation Revenues (Decrease)  (Decrease) 
 (In millions)  (In millions) 
 
Retail:  
Effect of 19.8% decrease in sales volumes $(307)
Effect of decrease in sales volumes $(447)
Change in prices 22  96 
      
  (285)  (351)
      
 
Wholesale:  
Effect of 3.1% increase in sales volumes 6 
Effect of decrease in sales volumes  (8)
Change in prices 30   (67)
      
 36   (75)
      
Net Decrease in Generation Revenues $(249) $(426)
      

 

6991

The decrease in retail generation sales volumesvolume was primarily due to an increase inincreased customer shopping in the Ohio Companies’ service territories of the pre-merger companies in the thirdsecond quarter of 2011, compared with the second quarter of 2010. That condition is expected to continue to impact the comparative sales levels for the remainder of 2010. Total generation KWH provided by alternative suppliers as a percentage of total KWH deliveries increased to 77% from 61% for the Ohio Companies increasedcompanies and to 64% in the third quarter of 201055% from 21% in the third quarter 2009.10% for Met-Ed’s and Penelec’s service areas.
The increasedecrease in wholesale generation revenues reflected increased capacity sales bylower RPM revenues for Met-Ed and Penelec in the PJM market. Transmission revenues decreased $90 million due to the termination of Met-Ed’s and Penelec’s TSC rates effective January 1, 2011. Transmission costs are now a component of the cost of generation established under Met-Ed’s and Penelec’s generation procurement plan.
The Allegheny companies added $707 million of revenues for the second quarter of 2011, including $155 million for distribution services, $486 million for generation sales and $66 million relating to transmission revenues.
Expenses -—
Total expenses decreasedincreased by $270$51 million due to the following:
Purchased power costs, excluding the Allegheny companies, were $252$483 million lower in the thirdsecond quarter of 20102011 due primarily to a decrease in volumes needed to serve the lower sales volumes.required. The decrease in power purchased from non-affiliates was partially offset by an increase in purchases from FES. The decrease in purchased power volumes from non-affiliates resulted principally fromFES reflected the termination of a third-party supply contract for Met-Ed and Penelec in January 2010 and from the above described increase in customer shopping indescribed above and the Ohio Companies’ service territories.
Prices paid for power purchased from non-affiliates in the third quarter of 2010 resulted from higher capacity prices in the PJM market for Met-Ed and Penelec compared to the third quarter of 2009, which is expected to continue for the remainder of the year. The decrease in unit costs on purchases from FES reflected a lower weighted average unit price under the Ohio Companies’ CBP and was partially offset by an increase in volume due to the replacementtermination of Met-Ed’s and Penelec’s terminated third-party contractpartial requirements PSA with supplyFES at the end of 2010. The increase in volumes purchased from FES.non-affiliates under Met-Ed’s and Penelec’s generation procurement plan effective January 1, 2011 was offset by a decrease in RPM expenses in the PJM market. The Allegheny companies added $336 million in purchased power costs in the second quarter of 2011.
        
 Increase  Increase 
Source of Change in Purchased Power (Decrease)  (Decrease) 
 (In millions)  (In millions) 
Pre-merger companies: 
Purchases from non-affiliates:  
Change due to decreased unit costs $(161)
Change due to increased volumes 88 
   
  (73)
   
Purchases from FES: 
Change due to increased unit costs $155  20 
Change due to decreased volumes  (443)  (398)
      
  (288)  (378)
      
Purchases from FES: 
Change due to decreased unit costs  (61)
Change due to increased volumes 45 
    
Increase in costs deferred  (32)
  (16)   
Total pre-merger companies  (483)
      
 
Decrease in costs deferred 52 
Purchases by Allegheny companies 336 
      
Net Decrease in Purchased Power Costs $(252) $(147)
      
Transmission costs increased by $87expenses decreased $29 million in the third quarter of 2010 primarily due to higherlower PJM network transmission expenses and congestion costs of $70 million for Met-Ed and Penelec.Penelec, partially offset by transmission expenses for the Allegheny companies of $41 million in the second quarter of 2011. Met-Ed and Penelec defer or amortize the difference between revenues from their transmission rider and transmission costs incurred with no material effect on current period earnings.
Administrative and 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, which are also recovered through rates, increased by $43 million.
The absence of a $7 million favorable JCP&L labor settlement that occurred in the second quarter of 2010.
Net amortization of regulatory assets decreased $71 million due primarily to reduced transition cost recovery and increased deferral of energy efficiency program costs increased $16 million in the third quarter of 2010 compared to the third quarter of 2009.costs.
•Fuel expenses for MP were $73 million in the second quarter of 2011.
•Operating expenses for the Allegheny companies were $95 million in the second quarter of 2011.
•Depreciation expense for the Allegheny companies was $48 million in the second quarter of 2011.

 

7092

Economic developmentMerger-related costs associated with the Ohio Companies’ ESP increased by $10$4 million in the thirdsecond 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 amortization2011 compared to the third quartersame period of 2009.2010.
General taxes increased $12$42 million primarily due to higherproperty taxes and gross receipts taxes incurred by the Allegheny companies in the thirdsecond quarter of 2010.2011.
Other Expense -—
Other expense increased $31$22 million in the thirdsecond quarter of 2011 due to interest expense on debt of the Allegheny companies.
Regulated Independent Transmission — Second Quarter 2011 Compared with Second Quarter 2010
Net income increased by $20 million in the second quarter of 2011 compared to the second quarter of 2010 compareddue to earnings associated with TrAIL and PATH ($22 million), partially offset by decreased earnings for ATSI ($1 million).
Revenues —
Revenues by transmission asset owner are shown in the thirdfollowing table:
             
  Three Months    
Revenues by Ended June 30  Increase 
Transmission Asset Owner 2011  2010  (Decrease) 
  (In millions) 
ATSI $54  $59  $(5)
TrAIL  46   —   46 
PATH  5   —   5 
          
Total Revenues $105  $59  $46 
          
Expenses —
Total expenses increased by $9 million principally due to TrAIL and PATH operating expenses.
Other Expense —
Other expense increased $6 million in the second quarter of 20092011 due primarily to lower investment income related to OE’s and TE’s nuclear decommissioning trusts ($23 million) and higheradditional interest expense associated with debt issuances by the Utilities since the third quarter of 2009 ($8 million).
TrAIL.
Competitive Energy Services — ThirdSecond Quarter 20102011 Compared with ThirdSecond Quarter 20092010
Net income decreased by $210$109 million in the thirdsecond quarter of 2011, compared to the second quarter of 2010, compared to the third quarter of 2009, primarily due to a $292 million impairment charge ($181 million netreduced sales margins, non-core asset impairments and the effect of tax) related to operational changes at certain smaller coal-fired units in response to the continued slow economy, lower demand for electricity and uncertainty related to proposed new federal environmental regulations. In addition, net income decreased due to lower investment income from the nuclear decommissioning trusts, partially offset by increased sales margins.mark-to-market adjustments.
Revenues -—
Total revenues increased $449by $479 million in the thirdsecond quarter of 20102011 primarily due to growth in direct and governmentgovernmental aggregation sales and POLR sales volumes,the inclusion of the Allegheny companies, partially offset by a decline in wholesalePOLR sales.

93

The increase in total revenues resulted from the following sources:
                        
 Three Months    Three Months   
 Ended September 30 Increase  Ended June 30 Increase 
Revenues by Type of Service 2010 2009 (Decrease)  2011 2010 (Decrease) 
 (In millions)  (In millions) 
Direct and Government Aggregation $717 $232 $485 
POLR 652 636 16 
Direct and Governmental Aggregation $925 $586 $339 
POLR and Structured Sales 231 615  (384)
Wholesale 66 77  (11)
Transmission 30 19 11 
RECs 12 — 12 
Other 38 37 1 
Allegheny Companies 511 — 511 
       
Total Revenues
 $1,813 $1,334 $479 
       
 
Allegheny Companies
 
Direct and Governmental Aggregation $26 
POLR and Structured Sales 185 
Wholesale 136 192  (56) 267 
Transmission 22 17 5  32 
Other 29 30  (1) 1 
          
Total Revenues $1,556 $1,107 $449  $511 
          
             
  Three Months    
  Ended June 30  Increase 
MWH Sales by Type of Service 2011  2010  (Decrease) 
  (In thousands)     
Direct  11,547   7,004   64.9%
Governmental Aggregation  3,970   2,715   46.2%
POLR and Structured Sales  3,718   11,600   (67.9)%
Wholesale  395   1,108   (64.4)%
Allegheny Companies  8,051   —   — 
          
Total Sales
  27,681   22,427   23.4%
          
             
Allegheny Companies
            
Direct  425         
POLR  2,169         
Structured Sales  846         
Wholesale  4,611         
            
Total Sales
  8,051         
            
The increase in direct and governmentgovernmental aggregation revenues of $485$339 million resulted from increased revenue from the acquisition of new commercial and industrial customers as well as new governmentgovernmental aggregation contracts with communities in Ohio, that providedproviding generation to 1.2approximately 1.5 million residential and small commercial customers at the end of September 2010June 2011 compared to 500,000 such customersapproximately 1.1 million at the end of September 2009. In addition,June 2010. Partially offsetting the increase, were sales to residential and small commercial customers that were bolsteredadversely affected by weather in the delivery areamarket served that was 60% warmer17% cooler than in 2009.2010.
The increasedecrease in POLR revenues of $16$384 million was due to higherlower sales volumes to Met-Ed, Penelec and the Ohio Companies, partially offset by increased sales to non-associated companies and higher unit prices to the Pennsylvania Companies consistent with our business strategy. Participation in POLR auctions and non-associated companies, partially offset by decreasedRFPs are expected to continue but the proportion of these sales volumes to the Ohio Companieswill depend on our hedge positions for direct retail and lower unit prices to both the Ohio Companies and the Pennsylvania Companies. The increased revenues from the Pennsylvania Companies resulted from FES supplying Met-Ed and Penelec with volumes previously supplied through a third-party contract and at prices that were slightly higher than in the third quarter of 2009.aggregation sales.
Wholesale revenues decreased $56$11 million due to reduced volumes and lowergeneration available for sale in the wholesale prices. The lower sales volumes were a result of using available capacity to serve increased retail sales in Ohio. In July 2010, FES entered into financial transactions that offset a portion of the mark-to-market impact of legacy purchased power contracts totaling 500 MW entered into in 2008 for delivery in 2010 and 2011 that have been marked to market since December 2009. These financial transactions mitigate the volatility of these contracts through the end of 2011 and resulted in wholesale revenues of $13 million for the quarter ended September 2010.market.

 

7194

The following tables summarize the price and volume factors contributing to changes in revenues:revenues (excluding the Allegheny companies):
        
 Increase  Increase 
Source of Change in Direct and Government Aggregation (Decrease) 
Source of Change in Direct and Governmental Aggregation (Decrease) 
 (In millions)  (In millions) 
Direct Sales:  
Effect of increase in sales volumes $277  $267 
Change in prices  (28)  (13)
      
 249  254 
      
Government Aggregation: 
Governmental Aggregation: 
Effect of increase in sales volumes 232  80 
Change in prices 4  5 
      
 236  85 
      
Net Increase in Direct and Government Aggregation Revenues $485 
Net Increase in Direct and Governmental Aggregation Revenues $339 
      
     
  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)
    
     
  Increase 
Source of Change in POLR and Structured Revenues (Decrease) 
  (In millions) 
POLR:    
Effect of decrease in sales volumes $(418)
Change in prices  34 
    
   (384)
    
Increase
Source of Change in Wholesale Revenues(Decrease)
(In millions)
Wholesale:
Effect of decrease in sales volumes(49)
Change in prices38
(11)
Transmission revenues increased $5by $11 million due primarily to higher MISOPJM congestion revenue. The revenues derived from the sale of RECs increased $12 million in the second quarter of 2011.
Expenses -—
Total expenses increased $664by $624 million in the thirdsecond quarter of 20102011 due to the following:
Fuel costs increased $99decreased by $27 million primarily due to increaseddecreased volumes ($56 million), partially offset by higher unit prices.prices ($29 million). Volumes increaseddecreased due to higherlower generation at the fossil units. UnitHigher unit prices declined primarily due to coal blend changes partially offset byreflect increased coal transportation expensescosts and higher nuclear fuel unit prices following the refueling outages that occurred in 2009.2010.
Purchased power costs increased $265 million due primarily towere unchanged as higher unit costs ($70 million) were offset by lower volumes purchased ($246 million) and a power contract mark-to-market adjustment ($26 million), partially offset by lower unit costs ($770 million). The increasedecrease in volume primarily relates to the assumptionabsence in 2011 of a 1,300 MW third party contract fromassociated with serving Met-Ed and Penelec.
Fossil operating costs decreased $16increased by $18 million due primarily to lower staffing levels, more capital related workhigher labor, contractor and reduced coal storage limitation charges.materials and equipment costs due to in increase in outages, both planned and unplanned, from the previous year.
Nuclear operating costs decreased $2increased by $33 million due primarily to lower laborhaving two refueling outages, Perry and related benefits, partially offset by higher professional and contractor costs in connection withBeaver Valley 2, occurring this year. While Davis-Besse had a refueling outages.outage last year, the work performed during the second quarter of 2010 was largely capital-related.
Transmission expenses increased $4by $66 million due primarily to increases in MISOPJM of $46$91 million from higher congestion, network, ancillary and congestion costs,line loss expense, partially offset by lower PJMMISO transmission expenses of $42$25 million due to lower congestionnetwork and line loss costs.
General taxes increased by $10 million due to an increase in revenue-related taxes.

95

Other expenses increased $314by $36 million primarily due toto: a $292$14 million mark-to-market adjustment; a $7 million impairment charge ($181 million net of tax) related to operational changes at Bay Shore units 2-4, Eastlake Plant units 1-4,non-core assets; and an $8 million increase in intercompany billings. The intercompany billings increased due to merger related costs and increased intersegment billings for leasehold costs from the Lake Shore Plant andOhio Companies.
The inclusion of the Ashtabula Plant. In addition, increased costs were incurred in uncollectible customer accounts and agent fees associated with the growth in direct and government aggregation sales.
Allegheny companies’ operations contributed $488 million to expenses, including a $9 million mark-to-market adjustment relating primarily to power contracts.
Other Expense -—
Total other expense in the thirdsecond quarter of 20102011 was $133$32 million higher than the thirdsecond quarter of 2009,2010, primarily due to a decrease in nuclear decommissioning trust investment income ($131 million) and a $2$34 million increase in net interest expense from new long-term debt issuedpartially offset by FESan increase in August 2009 combinedinvestment income ($2 million). The increase in interest expense was primarily due to the inclusion of the Allegheny companies ($22 million) and lower capitalized interest ($12 million) associated with the restructuringcompletion of existing PCRBs.the Sammis AQC project in 2010.

72

     
  Increase 
Source of Expense Changes (Decrease) 
  (In millions) 
     
Allegheny Companies
    
Fuel $238 
Purchased power  53 
Fossil  55 
Transmission  75 
Mark-to-Market  9 
General taxes  11 
Other  15 
Depreciation  32 
    
Total Expense $488 
    

Other — ThirdSecond Quarter of 20102011 Compared with ThirdSecond Quarter of 20092010
Financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a $79$47 million increasedecrease in earnings available to FirstEnergy in the thirdsecond quarter of 20102011 compared to the same period in 2009.2010. The increasedecrease resulted primarily from the absence of debt retirement costs that were incurred in the third quarter of 2009 in connection with a September 2009 tender offer for holding company debtincreased operating expenses resulting from adverse litigation resolution ($13929 million), decreased capitalized interest ($10 million) resulting from completed construction projects and increased interest expense resulting from that tender offerdue to the 2010 termination of interest rate swap agreements ($13 million) and increased investment income ($9 million), partially offset by increased income tax expense ($917 million).

96

Summary of Results of Operations — First NineSix Months of 20102011 Compared with the First NineSix Months of 20092010
Financial results for FirstEnergy’s major business segments in the first ninesix months of 20102011 and 20092010 were as follows:
                                    
 Energy Competitive Other and    Competitive Regulated Other and   
 Delivery Energy Reconciling FirstEnergy  Regulated Energy Independent Reconciling FirstEnergy 
First Nine Months 2010 Financial Results Services Services Adjustments Consolidated 
First Six Months 2011 Financial Results Distribution Services Transmission Adjustments Consolidated 
 (In millions)  (In millions) 
Revenues:  
External  
Electric $7,250 $2,302 $— $9,552  $4,527 $2,556 $— $— $7,083 
Other 423 151  (71) 503  226 180 172  (69) 509 
Internal* 79 1,812  (1,824) 67 
Internal — 661 —  (617) 44 
                    
Total Revenues 7,752 4,265  (1,895) 10,122  4,753 3,397 172  (686) 7,636 
                    
  
Expenses:  
Fuel — 1,089  (5) 1,084  97 991 — — 1,088 
Purchased power 4,159 1,239  (1,824) 3,574  2,323 700 —  (617) 2,406 
Other operating expenses 1,154 1,031  (73) 2,112  824 1,288 36  (10) 2,138 
Provision for depreciation 339 194 32 565  269 195 25 13 502 
Amortization of regulatory assets 549 — — 549  216 — 6 — 222 
Deferral of new regulatory assets — — — — 
Impairment of long lived assets — 294 — 294 
General taxes 481 86 20 587  356 95 16 12 479 
                    
Total Expenses 6,682 3,933  (1,850) 8,765  4,085 3,269 83  (602) 6,835 
                    
  
Operating Income 1,070 332  (45) 1,357  668 128 89  (84) 801 
                    
Other Income (Expense):  
Investment income 75 42  (24) 93  52 21 —  (21) 52 
Interest expense  (373)  (161)  (94)  (628)  (280)  (144)  (21)  (51)  (496)
Capitalized interest 4 67 51 122  4 22 1 11 38 
                    
Total Other Expense  (294)  (52)  (67)  (413)  (224)  (101)  (20)  (61)  (406)
                    
  
Income Before Income Taxes 776 280  (112) 944  444 27 69  (145) 395 
Income taxes 295 106  (37) 364  164 10 25  (20) 179 
                    
Net Income (Loss) 481 174  (75) 580  280 17 44  (125) 216 
Loss attributable to noncontrolling interest — —  (19)  (19) — — —  (15)  (15)
                    
Earnings available to FirstEnergy Corp. $481 $174 $(56) $599  $280 $17 $44 $(110) $231 
                    
                     
      Competitive  Regulated  Other and    
  Regulated  Energy  Independent  Reconciling  FirstEnergy 
First Six Months 2010 Financial Results Distribution  Services  Transmission  Adjustments  Consolidated 
  (In millions) 
Revenues:                    
External                    
Electric $4,641  $1,408  $—  $—  $6,049 
Other  157   106   116   (57)  322 
Internal  19   1,213   —   (1,165)  67 
                
Total Revenues  4,817   2,727   116   (1,222)  6,438 
                
                     
Expenses:                    
Fuel  —   684   —   —   684 
Purchased power  2,686   780   —   (1,165)  2,301 
Other operating expenses  690   692   30   (38)  1,374 
Provision for depreciation  210   148   19   6   383 
Amortization of regulatory assets  367   —   6   —   373 
General taxes  292   64   14   11   381 
                
Total Expenses  4,245   2,368   69   (1,186)  5,496 
                
                     
Operating Income  572   359   47   (36)  942 
                
Other Income (Expense):                    
Investment income  54   14   —   (21)  47 
Interest expense  (250)  (113)  (11)  (46)  (420)
Capitalized interest  2   47   1   31   81 
                
Total Other Expense  (194)  (52)  (10)  (36)  (292)
                
                     
Income Before Income Taxes  378   307   37   (72)  650 
Income taxes  143   117   14   (29)  245 
                
Net Income (Loss)  235   190   23   (43)  405 
Loss attributable to noncontrolling interest  —   —   —   (15)  (15)
                
Earnings available to FirstEnergy Corp. $235  $190  $23  $(28) $420 
                

 

7397

                                    
 Energy Competitive Other and   
 Delivery Energy Reconciling FirstEnergy 
First Nine Months 2009 Financial Results Services Services Adjustments Consolidated 
Changes Between First Six Months 2011 and Competitive Regulated Other and   
First Six Months 2010 Financial Results Regulated Energy Independent Reconciling FirstEnergy 
Increase (Decrease) Distribution Services Transmission Adjustments Consolidated 
 (In millions)  (In millions) 
Revenues:  
External  
Electric $8,322 $929 $— $9,251  $(114) $1,148 $— $— $1,034 
Other 433 400  (71) 762  69 74 56  (12) 187 
Internal — 2,349  (2,349) —   (19)  (552) — 548  (23)
                    
Total Revenues 8,755 3,678  (2,420) 10,013   (64) 670 56 536 1,198 
                    
  
Expenses:  
Fuel — 890 — 890  97 307 — — 404 
Purchased power 5,278 551  (2,349) 3,480   (363)  (80) — 548 105 
Other operating expenses 1,191 1,001  (89) 2,103  134 596 6 28 764 
Provision for depreciation 331 201 18 550  59 47 6 7 119 
Amortization of regulatory assets 903 — — 903   (151) — — —  (151)
Deferral of new regulatory assets  (136) — —  (136)
Impairment of long lived assets — — — — 
General taxes 486 84 17 587  64 31 2 1 98 
                    
Total Expenses 8,053 2,727  (2,403) 8,377   (160) 901 14 584 1,339 
                    
  
Operating Income 702 951  (17) 1,636  96  (231) 42  (48)  (141)
                    
Other Income (Expense):  
Investment income 111 136  (40) 207   (2) 7 — — 5 
Interest expense  (341)  (106)  (308)  (755)  (30)  (31)  (10)  (5)  (76)
Capitalized interest 3 42 51 96  2  (25) —  (20)  (43)
                    
Total Other Expense  (227) 72  (297)  (452)  (30)  (49)  (10)  (25)  (114)
                    
  
Income Before Income Taxes 475 1,023  (314) 1,184  66  (280) 32  (73)  (255)
Income taxes 190 409  (169) 430  21  (107) 11 9  (66)
                    
Net Income (Loss) 285 614  (145) 754 
Net Income 45  (173) 21  (82)  (189)
Loss attributable to noncontrolling interest — —  (14)  (14) — — — — — 
                    
Earnings available to FirstEnergy Corp. $285 $614 $(131) $768  $45 $(173) $21 $(82) $(189)
                    
                
Changes Between First Nine Months 2010 Energy Competitive Other and   
and First Nine Months 2009 Financial Results Delivery Energy Reconciling FirstEnergy 
Increase (Decrease) Services Services Adjustments Consolidated 
 (In millions) 
Revenues: 
External 
Electric $(1,072) $1,373 $— $301 
Other  (10)  (249) —  (259)
Internal* 79  (537) 525 67 
         
Total Revenues  (1,003) 587 525 109 
         
 
Expenses: 
Fuel — 199  (5) 194 
Purchased power  (1,119) 688 525 94 
Other operating expenses  (37) 30 16 9 
Provision for depreciation 8  (7) 14 15 
Amortization of regulatory assets  (354) — —  (354)
Deferral of new regulatory assets 136 — — 136 
Impairment of long lived assets — 294 — 294 
General taxes  (5) 2 3 — 
         
Total Expenses  (1,371) 1,206 553 388 
         
 
Operating Income 368  (619)  (28)  (279)
         
Other Income (Expense): 
Investment income  (36)  (94) 16  (114)
Interest expense  (32)  (55) 214 127 
Capitalized interest 1 25 — 26 
         
Total Other Expense  (67)  (124) 230 39 
         
 
Income Before Income Taxes 301  (743) 202  (240)
Income taxes 105  (303) 132  (66)
         
Net Income (Loss) 196  (440) 70  (174)
Loss attributable to noncontrolling interest — —  (5)  (5)
         
Earnings available to FirstEnergy Corp. $196 $(440) $75 $(169)
         
*Under the accounting standard for the effects of certain types of regulation, internal revenues are not fully offset for sale of RECs by FES to the Ohio Companies that are retained in inventory.

74

Energy Delivery ServicesRegulated Distribution — First NineSix Months of 20102011 Compared to First NineSix Months of 20092010
Net income increased by $196$45 million in the first ninesix months of 2010,2011, compared to the first ninesix months of 2009,2010, primarily due to the absence of CEI’s $216a $35 million regulatory asset impairment recorded in 2009,2010 and the earnings contribution of the Allegheny companies, partially offset by decreasesa favorable property tax settlement recognized in other operating expenses. Lower generation revenues were offset by lower purchased power expenses.2010.
Revenues -—
The decrease in total revenues resulted from the following sources:
                        
 Nine Months    Six Months   
 Ended September 30 Increase  Ended June 30 Increase 
Revenues by Type of Service 2010 2009 (Decrease)  2011 2010 (Decrease) 
 (In millions)  (In millions) 
Pre-merger companies: 
Distribution services $2,774 $2,578 $196  $1,719 $1,733 $(14)
              
Generation sales:  
Retail 3,540 4,679  (1,139) 1,620 2,272  (652)
Wholesale 628 544 84  220 397  (177)
              
Total generation sales 4,168 5,223  (1,055) 1,840 2,669  (829)
              
Transmission 638 808  (170) 88 299  (211)
Other 172 146 26  123 116 7 
              
Total pre-merger companies 3,770 4,817  (1,047)
Allegheny companies 983 — 983 
       
Total Revenues $7,752 $8,755 $(1,003) $4,753 $4,817 $(64)
              

98

The increasedecrease in distribution service revenues for the pre-merger companies primarily reflects lower transition revenues due to the completion of transition cost recovery for CEI in December 2010, partially offset by increased rates associated with the recovery of deferred distribution costs. Distribution deliveries (excluding the Allegheny companies) increased approximately 360,000 KWH (0.7%), primarily driven by an increase of 443,000 KWH (2.6%) in the industrial class. Distribution deliveries by customer class isare summarized in the following table:
Electric Distribution KWH Deliveries
Residential7%
Commercial3%
Industrial10%
Total Distribution KWH Deliveries7%
             
          Increase 
Electric Distribution KWH Deliveries 2011  2010  (Decrease) 
  (in thousands)     
Pre-merger companies:            
Residential  19,261   19,119   0.7%
Commercial  15,855   16,074   (1.4)%
Industrial  17,640   17,197   2.6%
Other  256   262   (2.3)%
          
Total pre-merger companies  53,012   52,652   0.7%
          
Allegheny companies  13,068   —   — 
          
Total Electric Distribution KWH Deliveries  66,080   52,652   25.5%
          
HigherLower distribution deliveries to residential and commercial customers reflected increasedsoft economic conditions in this sector and decreased weather-related usage in the first ninesix months of 2010. Cooling2011 as cooling degree days increased by 69%, partially offset by an 11% decrease in heating degree days fromwere 17% below the same period in 2009. In the2010. The increase in distribution deliveries to industrial sector, KWH deliveries increased to major automotive customers (22%), refinery customers (11%) and steel customers (44%)was primarily due to recovering economic conditions. The increaseconditions in distributionthe Utilities’ service revenues also reflectsterritory compared to the recoveryfirst six months of the Pennsylvania Energy Efficiency2010. Industrial deliveries increased by 12% to steel customers, 16% to electrical equipment and Conservation charges as approved by the PPUC in March 2010component manufacturing customers and the accelerated recovery of deferred distribution costs in Ohio,10% to non-metallic mineral customers, partially offset by a reduction in the transition rate for CEI effective June 1, 2009.2% lower sales to automotive customers.
The following table summarizes the price and volume factors contributing to the $1.1 billion$829 million decrease in generation revenues in the first ninesix months of 20102011 compared to the same period of 2009:2010:
        
 Increase  Increase 
Source of Change in Generation Revenues (Decrease)  (Decrease) 
 (In millions)  (In millions) 
Retail:  
Effect of 26.8% decrease in sales volumes $(1,254)
Effect of decrease in sales volumes $(826)
Change in prices 115  174 
      
  (1,139)  (652)
      
Wholesale:  
Effect of 7.1% decrease in sales volumes  (38)
Effect of decrease in sales volumes  (2)
Change in prices 122   (175)
      
 84   (177)
      
Net Decrease in Generation Revenues $(1,055) $(829)
      
The decrease in retail generation sales volumesvolume was primarily due to an increase inincreased customer shopping in the Ohio Companies’, Met-Ed’s and Penelec’s service territories in the first ninesix months of 2010. That condition is expected2011 compared to continue to impact the comparative sales levels for the remainder ofsame period in 2010. Total generation KWH provided by alternative suppliers as a percentage of total KWH deliveries increased to 75% from 57% for the Ohio Companies increasedcompanies and to 60% in the first nine months of 201048% from 7% in the same period of 2009. Higher generation revenues related to the recovery of transmission costs now provided9% for in the generation rate established under the May 2009 Ohio CBP partially offset theMet-Ed’s and Penelec’s service areas. The decrease in sales volumes.
The increase in wholesale generation revenues reflected higher prices and increased capacity sales bylower RPM revenues for Met-Ed and Penelec in the PJM market.
Transmission revenues decreased $211 million due to the termination of Met-Ed’s and Penelec’s TSC rates effective January 1, 2011. Transmission costs are now a component of the cost of generation established under Met-Ed’s and Penelec’s generation procurement plan.
The Allegheny companies added $983 million of revenues for the first six months of 2011, including $216 million for distribution services, $676 million from generation sales and $91 million relating to transmission revenues.

 

7599

Transmission revenues decreased $170 million primarily due to the termination of the Ohio Companies’ transmission tariff effective June 1, 2009; recovery of transmission costs is now through the generation rate established under the May 2009 Ohio CBP.
Expenses -—
Total expenses decreased by $1.4 billion$160 million due to the following:
Purchased power costs, excluding the Allegheny companies, were $1.1 billion$843 million lower in the first ninesix months of 2010 in large part2011 due to lower requirements to serve the lower sales volumes.a decrease in volumes required. The decrease in volumes from non-affiliates resulted principally from the termination of a third-party supply contract for Met-Ed and Penelec in January 2010 and from an increase in customer shopping in the Ohio Companies’ service territories described above. The decrease in volumespower purchased from FES also resulted fromreflected the increase in customer shopping in Ohio.
described above and the termination of Met-Ed’s and Penelec’s partial requirements PSA with FES at the end of 2010. The increase in volumes purchased from non-affiliates under Met-Ed’s and Penelec’s generation procurement plan effective January 1, 2011 was offset by a decrease in RPM expenses in the PJM market. The Allegheny companies added $481 million in purchased power unit costs from non-affiliates in the first ninesix months of 2010 resulted from higher capacity prices in the PJM market for Met-Ed and Penelec compared to the first nine months of 2009. The decrease in unit costs from FES was principally due to the lower weighted average unit price per KWH for the Ohio Companies established under the May 2009 CBP auction effective June 1, 2009.2011.
     
  Increase 
Source of Change in Purchased Power (Decrease) 
  (In millions) 
Purchases from non-affiliates:    
Change due to increased unit costs $506 
Change due to decreased volumes  (1,140)
    
   (634)
    
Purchases from FES:    
Change due to decreased unit costs  (230)
Change due to decreased volumes  (289)
    
   (519)
    
     
Decrease in costs deferred  34 
    
Net Decrease in Purchased Power Costs $(1,119)
    
Labor and employee benefit expenses decreased by $61 million due to lower pension and OPEB expenses and restructuring expenses recognized in 2009, and lower payroll costs resulting primarily from staffing reductions implemented in 2009.
Uncollectible expenses decreased $12 million due to lower generation revenues in Ohio in the first nine months of 2010 compared to the same period in 2009.
Expenses for economic development commitments related to the Ohio Companies’ ESP were lower by $11 million in the first nine months of 2010 compared to the same period of 2009.
     
  Increase 
Source of Change in Purchased Power (Decrease) 
  (In millions) 
Pre-merger companies:    
Purchases from non-affiliates:    
Change due to decreased unit costs $(356)
Change due to increased volumes  277 
    
   (79)
    
Purchases from FES:    
Change due to increased unit costs  63 
Change due to decreased volumes  (809)
    
   (746)
    
     
Increase in costs deferred  (18)
    
Total pre-merger companies  (843)
    
Purchases by Allegheny companies  481 
    
Net Decrease in Purchased Power Costs $(362)
    
Transmission expenses increased $44decreased $124 million primarily due to higherlower PJM network transmission expenses and congestion costs partially offset by lower MISO network transmission expenses that are not reflected in the generation rate established under the May 2009 Ohio CBP.
Amortization of regulatory assets decreased $354$177 million due primarily to the absence of the $216 million impairment of CEI’s regulatory assets in 2009, reduced net MISO and PJM transmission cost amortization and reduced CTC amortization for Met-Ed and Penelec, partially offset by transmission expenses for the Allegheny companies of $53 million in the first six months of 2011. Met-Ed and Penelec defer or amortize the difference between revenues from their transmission rider and transmission costs incurred with no material effect on earnings.
Energy efficiency program costs, which are also recovered through rates, increased $62 million.
The absence of a $7 million favorable JCP&L labor settlement that occurred in the second quarter of 2010.
A provision for excess and obsolete material of $13 million was recognized in the first six months of 2011 due to revised inventory practices adopted in conjunction with the Allegheny merger.
Net amortization of regulatory assets decreased $150 million primarily due to reduced net PJM transmission cost and transition cost recovery and the absence of a $35 million regulatory asset impairment recognized in 2010 associated with the filing of the Ohio Companies’ ESP.ESP on March 23, 2010, partially offset by increased energy efficiency cost recovery.
The deferral of new regulatory assets decreased $136Fuel expenses for MP were $97 million in the first ninesix months of 2011.
Operating expenses for the Allegheny companies were $131 million in the first six months of 2011.
Merger-related costs increased $46 million in the first six months of 2011 compared to the same period of 2010.
Depreciation expense for the Allegheny companies was $64 million.
General taxes increased by $64 million primarily due to taxes incurred by the Allegheny companies and the absence of a favorable property tax settlement recognized in 2010.
Other Expense —
Other expense increased by $30 million in the first six months of 2011 due to interest expense on debt of the Allegheny companies.
Regulated Independent Transmission — First Six Months 2011 Compared with First Six Months 2010
Net income increased by $21 million in the first six months of 2011 compared to the first six months of 2010 due to earnings associated with TrAIL and PATH ($27 million), partially offset by decreased earnings for ATSI ($6 million).

100

Revenues —
Revenues by transmission asset owner are shown in the absence of purchased power cost deferrals for CEI in 2009.
following table:
             
  Six Months    
Revenues by Ended June 30  Increase 
Transmission Asset Owner 2011  2010  (Decrease) 
  (In millions) 
ATSI $106  $116  $(10)
TrAIL  61   —   61 
PATH  5   —   5 
          
Total Revenues $172  $116  $56 
          
DepreciationExpenses —
Total expenses increased by $14 million principally due to TrAIL and PATH operating expenses.
Other Expense —
Other expense increased $8$10 million in the first six months of 2011 due to interest expense associated with TrAIL.
Competitive Energy Services — First Six Months of 2011 Compared to First Six Months of 2010
Net income decreased by $173 million in the first six months of 2011, compared to the first six months of 2010, primarily due to lower sales margin, an inventory reserve adjustment, non-core asset impairments and the effect of mark-to-market adjustments.
Revenues —
Total revenues increased $670 million in the first six months of 2011 primarily due to growth in direct and governmental aggregation sales and the inclusion of the Allegheny companies, partially offset by a decline in POLR sales.
The increase in total revenues resulted from the following sources:
             
  Six Months    
  Ended June 30  Increase 
Revenues by Type of Service 2011  2010  (Decrease) 
  (In millions) 
Direct and Governmental Aggregation $1,765  $1,097  $668 
POLR and Structured Sales  607   1,315   (708)
Wholesale  156   142   14 
Transmission  56   36   20 
RECs  44   67   (23)
Other  79   70   9 
Allegheny Companies  690   —   690 
          
Total Revenues
 $3,397  $2,727  $670 
          
             
Allegheny Companies
            
Direct and Governmental Aggregation $34         
POLR and Structured Sales  254         
Wholesale  357         
Transmission  44  ��      
Other  1         
            
Total Revenues
 $690         
            

101

             
  Six Months    
  Ended June 30  Increase 
MWH Sales by Type of Service 2011  2010  (Decrease) 
  (In thousands)     
Direct  21,219   12,857   65.0%
Governmental Aggregation  8,279   5,447   52.0%
POLR and Structured Sales  9,561   25,344   (62.3)%
Wholesale  1,380   1,538   (10.3)%
Allegheny Companies  10,687   —   — 
          
Total Sales
  51,126   45,186   13.1%
          
             
Allegheny Companies
            
Direct  570         
POLR  2,981         
Structured Sales  1,149         
Wholesale  5,987         
            
Total Sales
  10,687         
            
The increase in direct and governmental aggregation revenues of $668 million resulted from increased revenue from the acquisition of new commercial and industrial customers as well as new governmental aggregation contracts with communities in Ohio that provided generation to approximately 1.5 million residential and small commercial customers at the end of June 2011 compared to approximately 1.1 million customers at the end of June 2010.
The decrease in POLR revenues of $708 million was due to lower sales volumes to Met-Ed, Penelec and the Ohio Companies, partially offset by increased sales to non-associated companies and higher unit prices to the Pennsylvania Companies consistent with our business strategy. Participation in POLR auctions and RFPs are expected to continue but the proportion of these sales will depend on our hedge positions for our direct retail and aggregation sales.
Wholesale revenues increased by $14 million due to property additions sincehigher wholesale prices partially offset by decreased volumes. The lower sales volumes were the result of decreased short-term (net hourly positions) transactions in MISO. Additional capacity revenues earned by units moved to PJM were partially offset by losses on financially settled sales.
The following tables summarize the price and volume factors contributing to changes in revenues (excluding the Allegheny companies):
     
  Increase 
Source of Change in Direct and Governmental Aggregation (Decrease) 
  (In millions) 
Direct Sales:    
Effect of increase in sales volumes $493 
Change in prices  (20)
    
   473 
    
Governmental Aggregation:    
Effect of increase in sales volumes  176 
Change in prices  19 
    
   195 
    
Net Increase in Direct and Governmental Aggregation Revenues $668 
    

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  Increase 
Source of Change in POLR Revenues (Decrease) 
  (In millions) 
POLR:    
Effect of decrease in sales volumes $(819)
Change in prices  111 
    
   (708)
    
Increase
Source of Change in Wholesale Revenues(Decrease)
Wholesale:
Effect of decrease in sales volumes(15)
Change in prices29
14
Transmission revenues increased by $20 million due primarily to higher MISO and PJM congestion revenue. The revenues derived from the sale of RECs declined $23 million in the first six months of 2011.
Expenses —
Total expenses increased by $901 million in the first six months of 2011 due to the following:
Fuel costs decreased by $13 million primarily due to decreased volumes ($28 million), partially offset by higher unit prices ($15 million). Volumes decreased due to lower generation from the fossil units. Unit prices increased primarily due to increased coal transportation costs and higher nuclear fuel unit prices following the refueling outages that occurred in 2010.
Purchased power costs decreased by $154 million due primarily to lower volumes purchased ($248 million) partially offset by higher unit costs ($94 million). The decrease in volume primarily relates to the absence in 2011 of a 1,300 MW third party contract associated with serving Met-Ed and Penelec.
Fossil operating costs increased by $20 million due primarily to higher labor, contractor and material costs resulting from an increase in planned and unplanned outages.
Nuclear operating costs increased by $48 million due primarily to having two refueling outages, Perry and Beaver Valley 2, occurring this year. While Davis-Besse had a refueling outage last year, the work performed during the second quarter of 2009.2010 was largely capital-related.
Transmission expenses increased by $176 million due primarily to increases in PJM of $198 million from higher congestion, network, and line loss expense, partially offset by lower MISO transmission expenses of $22 million.
General taxes decreased $5increased by $12 million due to an increase in revenue-related taxes.
Other expenses increased by $93 million primarily due to: a $54 million provision for excess and obsolete material relating to favorablerevised inventory practices adopted in connection with the Allegheny merger; a $20 million impairment charge related to non-core assets; and a $9 million increase in intercompany billings. The intercompany billings increased due to merger related costs and increased intersegment billings for leasehold costs from the Ohio and Pennsylvania tax settlements in 2010 partially offset by higher gross receipts taxes.Companies.

 

76103

The inclusion of the Allegheny companies’ operations contributed $719 million to expenses, including a $43 million mark-to-market adjustment relating primarily to power contracts.
     
  Increase 
Source of Expense Changes (Decrease) 
  (In millions) 
Allegheny Companies
    
Fuel $320 
Purchased power  74 
Fossil  82 
Transmission  99 
Mark-to-Market  43 
General taxes  15 
Other  43 
Depreciation  43 
    
Total Expense $719 
    
Other Expense -—
OtherTotal other expense increased $67 million in the first ninesix months of 2011 was $49 million higher than the first six months of 2010, compared to the first nine months of 2009 primarily due to lowera $56 million increase in net interest expense, partially offset by an increase in nuclear decommissioning trust investment income ($367 million). The increase in interest expense was primarily due to the inclusion of the Allegheny companies ($30 million) and higherlower capitalized interest ($25 million) associated with the completion of the Sammis AQC project in 2010.
Other — First Six Months of 2011 Compared to First Six Months of 2010
Financial results from other operating segments and reconciling items, including interest expense associated withon holding company debt issuances byand corporate support services revenues and expenses, resulted in an $82 million decrease in earnings available to FirstEnergy in the Utilities sincefirst six months of 2011 compared to the thirdsame period in 2010. The decrease resulted primarily from increased operating expenses resulting from adverse litigation resolution ($29 million), decreased capitalized interest and increased depreciation expense resulting from completed construction projects placed into service ($27 million), an asset impairment charge in the first quarter of 20092011 ($3112 million) and increased income taxes ($9 million).
Regulatory Assets
FirstEnergy and the Utilities prepare their consolidated financial statements in accordance with the authoritative guidance for accounting for certain types of regulation. Under this guidance, regulatory assets represent incurred or accrued costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued liabilitiesamounts that have been deferred because it is probable such amounts willare expected to be returnedcredited to customers through future regulated rates.rates or amounts collected from customers for costs not yet incurred. FirstEnergy and the Utilities net their regulatory assets and liabilities based on federal and state jurisdictions. The following table provides the balance of net regulatory assets by Companycompany as of SeptemberJune 30, 20102011 and December 31, 20092010 and changes during the ninesix months then ended:
                        
 September 30, December 31, Increase  June 30, December 31, Increase 
Regulatory Assets 2010 2009 (Decrease)  2011 2010 (Decrease) 
 (In millions)  (In millions) 
OE $413 $465 $(52) $393 $400 $(7)
CEI 420 546  (126) 320 370  (50)
TE 74 70 4  89 72 17 
JCP&L 722 888  (166) 469 513  (44)
Met-Ed 400 357 43  341 296 45 
Penelec 203 9 194  222 163 59 
Other 14 21  (7)
Other* 348 12 336 
              
Total $2,246 $2,356 $(110) $2,182 $1,826 $356 
              
*2011 includes $337 million related to the Allegheny companies.

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The following table providestables provide information about the composition of net regulatory assets as of SeptemberJune 30, 20102011 and December 31, 20092010 and the changes during the ninesix months then ended:
                
 Amount of 
 Increase 
             (Decrease) 
 September 30, December 31, Increase  June 30, December 31, Increase Attributable 
Regulatory Assets by Source 2010 2009 (Decrease)  2011 2010 (Decrease) to AE 
 (In millions)  (In millions) 
Regulatory transition costs $1,168 $1,100 $68  $899 $770 $129 $— 
Customer shopping incentives 26 154  (128)
Customer receivables for future income taxes 330 329 1  502 326 176 160 
Loss on reacquired debt 50 51  (1) 53 48 5 8 
Employee postretirement benefits 17 23  (6) 11 16  (5) — 
Nuclear decommissioning, decontamination and spent fuel disposal costs  (173)  (162)  (11)
Nuclear decommissioning and spent fuel disposal costs  (201)  (184)  (17) — 
Asset removal costs  (238)  (231)  (7)  (228)  (237) 9 22 
MISO/PJM transmission costs 194 148 46  292 184 108 76 
Deferred generation costs 393 369 24  454 386 68 15 
Distribution costs 392 482  (90) 284 426  (142) — 
Other 87 93  (6) 116 91 25 56 
                
Total $2,246 $2,356 $(110) $2,182 $1,826 $356 $337 
                
FirstEnergy had $385 million of net regulatory liabilities as of June 30, 2011, including $376 million of net regulatory liabilities acquired as part of the merger with AE that are primarily related to customer receivables for future income taxes and asset removal costs.
Regulatory assets that do not earn a current return totaled approximately $181$345 million as of SeptemberJune 30, 2010 (JCP&L — $402011, of which $138 million Met-Ed — $124 million, Penelec — $9 million and CEI $5 million). relates to purchase accounting fair value adjustments to corresponding liabilities that do not accrue interest.
Regulatory assets not earning a current return (primarily for Met-Ed and Penelec include certain regulatory transition costs and employee postretirement benefits)PJM transmission costs of approximately $144 million and $34 million, respectively. The regulatory transition costs are expected to be recovered by 20142020.
Regulatory assets not earning a current return for JCP&L and by 2020 for Met-Ed and Penelec.
Competitive Energy Services — First Nine Months of 2010 Compared to First Nine Months of 2009
Net income decreased by $440 million in the first nine months of 2010, compared to the first nine months of 2009, primarily due to a $292 million impairment charge ($181 million net of tax) related to operational changes atinclude certain smaller coal-fired units in response to the continued slow economy, lower demand for electricity, as well as uncertainty related to proposed new federal environmental regulations. In addition, the absence of a $252 million ($158 million after tax) gain in 2009 from the sale of a 9% participation interest in OVEC, lower investment income from nuclear decommissioning trusts and a decrease in sales margins also contributed to the decline in net income.

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Revenues -
Excluding the impact of the 2009 gain on the OVEC sale, total revenues increased $839 million in the first nine months of 2010 compared to the same period in 2009 primarily due to an increase in direct and government aggregation sales volumes and sales of RECs, partially offset by decreases in POLR sales to the Ohio Companies and wholesale sales.
The increase in reported segment revenues resulted from the following sources:
             
  Nine Months    
  Ended September 30  Increase 
Revenues by Type of Service 2010  2009  (Decrease) 
  (In millions) 
Direct and Government Aggregation $1,814  $406  $1,408 
POLR  1,911   2,369   (458)
Wholesale  322   503   (181)
Transmission  58   57   1 
RECs  67   —   67 
Sale of OVEC participation interest  —   252   (252)
Other  93   91   2 
          
Total Revenues $4,265  $3,678  $587 
          
The increase in direct and government aggregation revenues of $1,408 million resulted from increased revenue from the acquisition of new commercial and industrial customers, as well as new government aggregation contracts with communities in Ohio that provide generation to 1.2 million residential and small commercial customers at the end of September 2010 compared to 500,000 such customers at the end of September 2009, partially offset by lower unit prices. In addition, sales to residential and small commercial customers were bolstered by weather in the delivery area that was 69% warmer than in 2009.
The decrease in POLR revenues of $458 million was due to lower sales volumes and lower unit prices to the Ohio Companies, partially offset by increased sales volumes and higher unit prices to the Pennsylvania Companies. The lower sales volumes and unit prices to the Ohio Companies in 2010 reflected the results of the May 2009 CBP. The increased revenues to the Pennsylvania Companies resulted from FES supplying Met-Ed and Penelec with volumes previously supplied through a third-party contract and at prices that were slightly higher than in 2009.
Wholesale revenues decreased $181 million due to reduced volumes and lower prices. The lower sales volumes were due to available capacity serving increased retail sales in Ohio. In July 2010, FES entered into financial transactions that offset the mark-to-market impact of legacy purchased power contracts totaling 500 MW entered into in 2008 for delivery in 2010 and 2011 that have been marked to market since December 2009. These financial transactions mitigate the volatility of these contracts through the end of 2011 and resulted in wholesale revenues of $13 million in 2010.
The sale of RECs resulted in additional gains of $67 million in the nine months ending September 2010.
The following tables summarize the price and volume factors contributing to changes in revenues from generation sales:
     
  Increase 
Source of Change in Direct and Government Aggregation (Decrease) 
  (In millions) 
Direct Sales:    
Effect of increase in sales volumes $909 
Change in prices  (73)
    
   836 
    
Government Aggregation:    
Effect of increase in sales volumes  570 
Change in prices  2 
    
   572 
    
Net Increase in Direct and Government Aggregation Revenues $1,408 
    

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  Increase 
Source of Change in Wholesale Revenues Decrease 
  (In millions) 
POLR:    
Effect of 8.4% decrease in sales volumes $(200)
Change in prices  (258)
    
   (458)
    
Other Wholesale:    
Effect of 44.6% decrease in sales volumes  (147)
Change in prices  (34)
    
   (181)
    
Net Decrease in Wholesale Revenues $(639)
    
Transmission revenues increased $1 million due primarily to higher MISO congestion revenue, offset by lower PJM congestion revenue.
Expenses -
Total expenses increased $1.2 billion in the first nine months of 2010 due to the following factors:
Fuel costs increased $199 million due to increased generation volumes ($140 million) and higher unit prices ($59 million). The increase in unit prices was due primarily to increased coal transportationstorm damage costs and higher nuclear fuel unit prices following the refueling outagespension and postretirement benefits of approximately $34 million that occurred in 2009.
are expected to be recovered by 2014.
Purchased power costs increased $688 million due primarily to higher volumes purchased ($606 million), power contract mark-to-market adjustments ($43 million) and higher unit costs ($39 million).
Fossil operating costs decreased $18 million due primarily to lower labor costs which were partially offset by higher professional and contractor costs and reduced gains on the sale of emission allowances.
Nuclear operating costs decreased $39 million due primarily to lower labor, consulting and contractor costs. The nine months ended September 2010 had one less refueling outage and fewer extended outages than the same period of 2009.
Transmission expenses increased $36 million due primarily to increased costs in MISO of $152 million from higher network, ancillary and congestion costs, partially offset by lower PJM transmission expenses of $116 million due to lower congestion costs.
Other expenses increased $340 million primarily due toRegulatory assets not earning 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 -
Totalcurrent return for FirstEnergy’s other expense in the nine months ending September 2010 was $124 million higher than the same period in 2009, primarily due to a decrease in nuclear decommissioning trust investment income ($94 million) and a $30 million increase in net interest expense from new long-term debt issued combined with the restructuring of existing PCRBs.
Other — First Nine Months of 2010 Compared to First Nine Months of 2009
Financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a $75 million increase in earnings available to FirstEnergy in the first nine months of 2010 compared to the same period in 2009. The increase resulted primarily from the absence of debt retirement costs that were incurred in the third quarter of 2009 in connection with the tender offer for holding company debt ($139 million), decreased interest expense associated with the debt retirement ($56 million) and increased interest income ($16 million), partially offset by increased depreciationutility subsidiaries include certain deferred generation and other operating expenses ($30 million) and income tax expense ($132 million).
costs of approximately $133 million that are expected to be recovered though 2026.
CAPITAL RESOURCES AND LIQUIDITY
As of SeptemberJune 30, 2010,2011, FirstEnergy had $476 million of cash and cash equivalents of approximately $632 million available to fund investments, operations and capital expenditures. ToIn addition to internal sources to fund liquidity and capital requirements for the balance of 20102011 and beyond, FirstEnergy willmay rely on internal and external sources of funds. Short-term cash requirements not met by cash provided from operations are generally satisfied through short-term borrowings. Long-term cash needs may be met through issuances of debt and/or equity securities.

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

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As of SeptemberJune 30, 2010,2011, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was principally due to short-term borrowings ($1.0 billion) and the classification of certain variable interest rate PCRBs as currently payable long-term debt.debt and short-term borrowings. Currently payable long-term debt as of SeptemberJune 30, 2010,2011, included the following (in millions):
     
Currently Payable Long-term Debt    
PCRBs supported by bank LOCs(1)
 $1,318 
FGCO and NGC unsecured PCRBs(1)
  90 
Penelec FMBs(2)
  24 
NGC collateralized lease obligation bonds  50 
Sinking fund requirements  34 
Other notes(3)
  74 
    
  $1,590 
    
     
Currently Payable Long-term Debt    
PCRBs supported by bank LOCs (1)
 $949 
AE Supply unsecured note  503 
FirstEnergy Corp. unsecured note  250 
FGCO and NGC unsecured PCRBs (1)
  136 
WP unsecured note  80 
NGC collateralized lease obligation bonds  59 
Sinking fund requirements  50 
Other notes  31 
    
  $2,058 
    
   
(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-TermCredit Facility Borrowings and Liquidity
FirstEnergy had approximately $1.0 billion$656 million and $700 million of short-term borrowings as of SeptemberJune 30, 20102011 and $1.2 billion as of December 31, 2009.2010, respectively. FirstEnergy’s available liquidity as of October 22, 2010,July 29, 2011, is summarized in the following table:
                              
 Available  Available 
Company Type Maturity Commitment Liquidity  Type Maturity Commitment Liquidity 
     (In millions)      (In millions) 
FirstEnergy(1)
 Revolving Aug. 2012 $2,750 $1,650  Revolving June 2016 $2,000 $1,751 
FirstEnergy Solutions Term loan Mar. 2011 100 — 
Ohio and Pennsylvania Companies Receivables financing Various(2) 395 245 
FES / AE Supply Revolving June 2016 2,500 2,449 
TrAIL Revolving Jan. 2013 450 450 
AGC Revolving Dec. 2013 50 — 
            
 Subtotal $3,245 $1,895    Subtotal $5,000 $4,650 
 Cash — 911    Cash — 586 
            
 Total $3,245 $2,806    Total $5,000 $5,236 
            
   
(1) FirstEnergy Corp. and regulated 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 PeakDuring March 2011, the accounts receivable financing arrangements for OE, TE, Penelec and Global Rail entered into a $350Met-Ed were terminated in favor of other sources of liquidity that were deemed more economical. In May 2011, AE terminated its $250 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 FEVcredit facility. AE now participates 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 tounregulated money pool (see 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.Money Pools below).
Revolving Credit FacilityFacilities
On June 17, 2011, FirstEnergy has the capabilityand certain of its subsidiaries entered into two new five-year syndicated revolving credit facilities with aggregate commitments of $4.5 billion (New Facilities).
An aggregate amount of $2 billion is available to request an increase in the total commitments availablebe borrowed under a syndicated revolving credit facility (New FirstEnergy Facility), subject to separate borrowing sublimits for each borrower. The borrowers under the New FirstEnergy Facility are FirstEnergy, CEI, Met-Ed, OE, Penn, TE, ATSI, JCP&L, MP, Penelec, PE and WP. An additional $2.5 billion is available to be borrowed by FES and AE Supply under a separate syndicated revolving credit facility (New FES/AESupply Facility).
The New Facilities replaced a FirstEnergy $2.75 billion revolving credit facility, (included inan AE Supply $1 billion revolving credit facility, a MP $110 million revolving credit facility, a PE $150 million revolving credit facility and a WP $200 million revolving credit facility, all of which were terminated as of June 17, 2011. Initial borrowings under the borrowing capability table above) upNew Facilities were used to a maximum of $3.25 billion, subject to the discretion ofpay off outstanding obligations under these prior revolving credit facilities.
Commitments under 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 areNew Facilities will be available until August 24, 2012,June 17, 2016, unless the lenders agree, at the request of the applicable borrowers, to an unlimited number ofup to two additional one-year extensions. Generally, borrowings under each of the facility must be repaid within 364 days. Available amounts forNew Facilities are available to each borrower separately and will mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended.
Borrowings under each of the New Facilities are subject to acceleration upon the occurrence of events of default that each borrower considers usual and customary, including a specified sub-limit, as well as applicable regulatory andcross-default for other limitations.indebtedness in excess of $100 million. Defaults by either FES or AE Supply or their respective subsidiaries under the New FES/AESupply Facility or other indebtedness generally will not cross-default to FirstEnergy under the New FirstEnergy Facility.

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The following table summarizes the borrowing sub-limits for each borrower under the facility,facilities, as well as the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations as of SeptemberJune 30, 2010:2011:
                
 Revolving Regulatory and  New 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) $2,000  —(a)
FES 1,000  —(1) $1,500  —(b)
AE Supply $1,000  —(b)
OE 500 500  $500 $500 
Penn 50  34(2)
CEI  250(3) 500  $500 $500 
TE  250(3) 500  $500 $500 
JCP&L 425  410(2) $425 $411(c)
Met-Ed 250  300(2) $300 $300(c)
Penelec 250  300(2) $300 $300(c)
West Penn $200 $200(c)
MP $150 $150(c)
PE $150 $150(c)
ATSI  50(4) 50  $100 $100 
Penn $50 $33(c)
   
(1)(a) No regulatory approvals, statutory or charter limitations applicable.limitations.
 
(2)(b)No limitation based upon blanket financing authorization from the FERC under existing open market tariffs.
(c) Excluding amounts thatwhich may be borrowed under the regulated companies’ money pool.
(3)Borrowing sub-limits
The entire amount of the New FES/AE Supply Facility and $700 million of the New FirstEnergy Facility, subject to each borrower’s sub-limit, is available 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 each of the facilityNew Facilities and against the applicable borrower’s borrowing sub-limit.
The revolving credit facilityEach of the New Facilities contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%, measured at the end of each fiscal quarter. As of SeptemberJune 30, 2010,2011, FirstEnergy’s and its subsidiaries’ debt to total capitalization ratios (as defined under each of the revolving credit facility)New Facilities) were as follows:
     
Borrower    
FirstEnergy
  60.256.9%
FES
  53.254.1%
OE
  53.156.2%
Penn
  30.834.4%
CEI
  57.656.3%
TE
  57.758.4%
JCP&L
  34.443.9%
Met-Ed
  37.653.5%
Penelec
  51.855.5%
ATSI
  48.854.9%
MP
59.3%
PE
60.1%
WP
53.9%
AE Supply
39.4%

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As of SeptemberJune 30, 2010,2011, FirstEnergy could issue additional debt of approximately $2.9$7.8 billion, or recognize a reduction in equity of approximately $1.6$4.2 billion, and remain within the limitations of the financial covenants required by its revolving credit facility.

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The revolving credit facility doesNew Facilities do not contain provisions that either restrict the ability to borrow or accelerate repaymentpayment of outstanding advances as a result of any change in credit ratings. Pricing is defined in “pricing grids,” whereby the cost of funds borrowed under the facility isfacilities are related to the credit ratings of the company borrowing the funds.
In addition to the New Facilities, FirstEnergy also has access to an additional $500 million of revolving credit facilities relating to the Allegheny companies (TrAIL — $450 million and AGC $50 million).
Under the terms of its credit facility, outstanding debt of AGC may not exceed 65% of the sum of its debt and equity as of the last day of each calendar quarter. Outstanding debt for TrAIL may not exceed 70% and 65% of the sum of its debt and equity as of the last day of each calendar quarter through June 30, 2011 and December 31, 2012, respectively. These provisions limit debt levels of these subsidiaries and also limit the net assets of each subsidiary that may be transferred to AE.
FirstEnergy Money Pools
FirstEnergy’s regulated companies, excluding regulated companies acquired in the Allegheny merger, also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy’s unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first ninesix months of 20102011 was 0.53%0.43% per annum for the regulated companies’ money pool and 0.60%0.46% per annum for the unregulated companies’ money pool. FirstEnergy and its regulated companies acquired in the Allegheny merger have filed with the appropriate regulatory commissions to receive approval to become part of the FirstEnergy regulated money pool.
Pollution Control Revenue Bonds
As of SeptemberJune 30, 2010,2011, FirstEnergy’s currently payable long-term debt included approximately $1.3 billion$949 million (FES — $1.2 billion,$875 million, Met-Ed — $29 million and Penelec — $45 million) of variable interest rate PCRBs, the bondholders of which are entitled to the benefit of irrevocable direct pay bank LOCs. The interest rates on the PCRBs are reset daily or weekly. Bondholders can tender their PCRBs for mandatory purchase prior to maturity with the purchase price payable from remarketing proceeds or, if the PCRBs are not successfully remarketed, by drawings on the irrevocable direct pay LOCs. The subsidiary obligor is required to reimburse the applicable LOC bank for any such drawings or, if the LOC bank fails to honor its LOC for any reason, must itself pay the purchase price.
The LOCs for FirstEnergy variable interest rate PCRBs were issued by the following banks as of SeptemberJune 30, 2010:2011:
                
 Aggregate LOC Reimbursements of Aggregate LOC Reimbursements of
LOC Bank Amount(2) LOC Termination Date LOC Draws Due Amount(1) LOC Termination Date LOC Draws Due
 (In millions)  (In millions) 
UBS $272 April 2014 April 2014
The Bank of Nova Scotia 178 Beginning June 2012 Multiple dates(2)
CitiBank N.A. $166 June 2014 June 2014 165 June 2014 June 2014
The Bank of Nova Scotia 284 Beginning April 2011 Multiple dates(3)
Wachovia Bank 153 March 2014 March 2014
The Royal Bank of Scotland 131 June 2012 6 months 131 June 2012 6 months
Wachovia Bank 152 March 2014 March 2014
Barclays Bank(1)
 528 Beginning December 2010 30 days
PNC Bank 70 Beginning November 2010 180 days
US Bank 60 April 2014 6 months
            
Total $1,331     $959    
            
   
(1) Supported by 18 participating banks, with no one bank having more than 14% of the total commitment.
(2)Includes approximately $13$10 million of applicable interest coverage.
 
(3)(2) Shorter of 6 months or LOC termination date ($15549 million) and shorter of one year or LOC termination date ($129 million).
On August 20, 2010,March 17, 2011, FES completed the remarketing of $250$207 million variable rate PCRBs. These PCRBs remained in a variable interest mode, supported by bank LOC’s. Also, on March 1, 2011, FES repurchased $50 million of PCRBs. Ofnon-LOC backed fixed rate PCRBs that were subject to purchase on demand by the $250owner on that date.
On April 1, 2011, FES completed the remarketing of an additional $97 million $235of non-LOC backed commercial paper rate and fixed rate PCRBs (including the $50 million repurchased on March 1) into variable rate modes with LOC support. Also on April 1, 2011, Penelec completed the remarketing of $25 million of non-LOC backed commercial paper rate PCRBs into a variable rate mode with LOC support.

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In connection with the remarketings, approximately $207 million aggregate principal amount of FMBs previously delivered to LOC providers were cancelled, and approximately $50 million aggregate principal amount of FMBs delivered to secure PCRBs were cancelled on May 31, 2011.
On April 29, Met-Ed redeemed $14 million of PCRBs were converted from a variable interest rate to a fixed interest rate. The remaining $15at par value.
On June 1, 2011, FGCO repurchased $40 million of PCRBs continueand, subject to bear a fixed interest rate. The interest rate conversion minimizes financial risk by convertingmarket conditions and other considerations, is holding those bonds for future remarketing or refinancing.
On July 29, 2011, FGCO and NGC provided notice to the long-term debt into a fixed ratetrustee for $158.1 million and as$158.9 million, respectively, of PCRBs of their election to terminate applicable supporting LOCs. As a result, reducing exposure to variable interest rates over the short-term. These remarketings included two series: $235 million ofthese PCRBs that now bear a per-annum rate of 2.25% and are subject to mandatory purchase on June 3, 2013;September 1, 2011. Subject to market conditions and $15other considerations, FGCO and NGC currently expect to hold the bonds for future remarketing or refinancing. Also, approximately $28.5 million and $98.9 million aggregate principal amount of PCRBs that now bear a per-annum rateFMBs previously delivered to certain of 1.5%the LOC providers by FGCO and are subject toNGC, respectively, will be cancelled in connection with the mandatory purchase on June 1, 2011.

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On October 1, 2010, FES completed the refinancing and remarketing of six series of PCRBs totaling $313 million. These PCRBs were converted from a variable interest rate to a fixed long term interest rate of 3.375% per annum and are subject to mandatory purchase on July 1, 2015. The LOCs for the refinanced series of PCRBs totaling $208 million terminated as of October 1, 2010. The LOCs for the remarketed series of PCRBs totaling $108 million will terminate on November 1, 2010.purchases.
Long-Term Debt Capacity
As of SeptemberJune 30, 2010,2011, the Ohio Companies and Penn had the aggregate capability to issue approximately $2.5 billion of additional FMBs on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMBs by the Ohio Companies is also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMBs) supporting pollution control notes or similar obligations, or as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE and CEI to incur additional secured debt not otherwise permitted by a specified exception of up to $116$100 million and $25$19 million, respectively, as of September 30, 2010.respectively. As a result of theits indenture provisions, TE cannot incur any additional secured debt. Met-Ed and Penelec had the capability to issue secured debt of approximately $380$363 million and $358$365 million, respectively, under provisions of their senior note indentures as of SeptemberJune 30, 2010.
Based2011. In addition, based upon FGCO’stheir respective FMB indenture,indentures, net earnings and available bondable property additions as of SeptemberJune 30, 2010,2011, MP, PE and WP had the capability to issue approximately $1.0 billion of additional FMBs in the aggregate.
Based upon FGCO’s net earnings and available bondable property additions under its FMB indentures as of June 30, 2011, FGCO had the capability to issue $1.9$2.5 billion of additional FMBs under the terms of that indenture. Due to the sale of Fremont Energy Center on July 28, 2011, FGCO’s capability to issue additional FMBs was reduced by $510 million. Based upon NGC’s FMB indenture, net earnings and available bondable property additions under its FMB indenture as of June 30, 2011, NGC had the capability to issue $294 million$1.7 billion of additional FMBs as of SeptemberJune 30, 2010.2011 under the terms of that indenture.
FirstEnergy’s access to capital markets and costs of financing are influenced by the ratings of its securities. On February 11, 2010, S&P issued a report lowering FirstEnergy’s and its subsidiaries’ credit ratings by one notch, while maintaining its stable outlook.25, 2011, Moody’s and Fitch affirmed the ratings and stable outlook of FirstEnergy and its subsidiaries on February 11, 2010. On September 28, 2010, S&P issued a report reaffirmingregulated utilities, upgraded AE’s senior unsecured ratings to Baa3 from Ba1 and placed the ratings for FES under review for possible downgrade. On March 1, 2011, Fitch affirmed the ratings and stable outlook of FirstEnergy and its subsidiaries. The following table displays FirstEnergy’s FES’ and the Utilities’its subsidiaries’ securities ratings as of September 30, 2010.July 29, 2011.
             
  Senior Secured Senior Unsecured
Issuer S&P Moody’s Fitch S&P Moody’s Fitch
FirstEnergy Corp. — — — BB+ Baa3 BBB
FirstEnergy SolutionsAllegheny———BB+Baa3—
FES — — — BBB- Baa2 BBB
Ohio EdisonAE SupplyBBBBaa2BBBBBB-Baa3BBB-
AGC———BBB-Baa3BBB+
ATSI———BBB-Baa1A-
CEIBBBBaa1BBBBBB-Baa3BBB-
JCP&L———BBB-Baa2BBB+
Met-EdBBBA3A-BBB-Baa2BBB+
MPBBB+Baa1A-BBB-Baa3BBB+
OE BBB A3 BBB+ BBB- Baa2 BBB
Pennsylvania PowerPenelecBBBA3BBB+BBB-Baa2BBB
Penn BBB+ A3 BBB+ — — —
Cleveland Electric IlluminatingPE BBBBBB+ Baa1 BBBA- BBB- Baa3 BBB-BBB+
Toledo EdisonTE BBB Baa1 BBB — — —
Jersey Central Power & LightTrAIL — — — BBB- Baa2 BBB+A-
Metropolitan EdisonWP BBBBBB+ A3 BBB+A- BBB- Baa2 BBB
Pennsylvania ElectricBBBA3BBB+BBB-Baa2BBB
ATSI———BBB-Baa1—
Changes in Cash Position
As of SeptemberJune 30, 2010,2011, FirstEnergy had $632$476 million of cash and cash equivalents compared to $874 millionapproximately $1 billion as of December 31, 2009.2010. As of SeptemberJune 30, 20102011 and December 31, 2009,2010, FirstEnergy had approximately $14$78 million and $12$13 million, respectively, of restricted cash included in other current assets on the Consolidated Balance Sheet.

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During the first ninesix months of 2010,2011, FirstEnergy received $730 million of$1.4 billion from cash dividends fromand equity repurchases by its subsidiaries and paid $503$420 million in cash dividends to common shareholders, including $20 million paid in March by AE to its former shareholders.
Cash Flows From Operating Activities
FirstEnergy’s consolidated net cash from operating activities is provided primarily by its competitive energy services, and energy delivery services and regulated independent transmission businesses (see Results of Operations above). Net cash provided from operating activities increased by $609$173 million during the first ninesix months of 20102011 compared to the comparablesame period in 2009,2010, as summarized in the following table:
                        
 Nine Months    Six Months   
 Ended September 30 Increase  Ended June 30 Increase 
Operating Cash Flows 2010 2009 (Decrease)  2011 2010 (Decrease) 
 (In millions)  (In millions) 
Net income $580 $754 $(174) $216 $405 $(189)
Non-cash charges and other adjustments 1,648 1,755  (107)
Non-cash charges 1,229 789 440 
Pension trust contribution —  (500) 500   (262) —  (262)
Working Capital and other  (155)  (545) 390 
Working capital and other  (152)  (336) 184 
              
 $2,073 $1,464 $609  $1,031 $858 $173 
              

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The decreaseincrease in non-cash charges and other adjustments is primarily due to lower net amortization of regulatory assets of ($354 million), including the impact of CEI’s $216 million regulatory asset impairment recorded during the first quarter of 2009, a $142 million charge relating to loss on debt redemptions during the third quarter of 2009 and changes inincreased deferred income taxes and investment tax credits ofdriven by bonus depreciation and the 2011 pension contribution ($162393 million). The decrease in non-cash charges and other adjustments wasincreased depreciation from the acquired Allegheny Companies ($119 million), partially offset by impairmentlower amortization of long-lived assets of $294 million, including the impact of the $292 million impairment of certain FGCO facilities and changes in the deferral of new regulatory assets of $136 million.from reduced net PJM transmission cost and transition cost recovery ($151 million).
The changeincrease in cash flows from working capital and other is primarily due to cash proceedsdecreased receivables from higher customer collections ($355 million) and decreased materials and supplies from the inventory valuation adjustment in the first quarter of $129 million received on the termination of fixed-for-floating interest rate swaps during the second2011 ($41 million), partially offset by increased prepayments and third quarters of 2010, changes in investment securities of $133 million, a decrease inother current assets driven by higher prepaid assets of $345 million and a $250 million increase in accounts receivable.taxes ($187 million).
Cash Flows From Financing Activities
In the first ninesix months of 2010,2011, cash used for financing activities was $870$1,039 million compared to cash provided from financing activities of $617$484 million in the first nine monthscomparable period of 2009. The decrease was primarily due to activity during the first nine months of 2009 which included new debt issuances and long-term debt retirements associated with a $1.2 billion senior note tender offer completed by FirstEnergy in September 2009.2010. The following table summarizes security issuancesnew debt financing (net of any discounts) and redemptions:
                
 Nine Months  Six Months 
 Ended September 30  Ended June 30 
Securities Issued or Redeemed 2010 2009 
Debt Issuances and Redemptions 2011 2010 
 (In millions)  (In millions) 
New Issues
  
First mortgage bonds — 398 
Pollution control notes 250 859  $272 $— 
Senior secured notes — 297 
Long-term revolving credit 70 — 
Unsecured Notes 1 2,597  161 — 
          
 $251 $4,151  $503 $— 
          
  
Redemptions
  
Pollution control notes $312 $251 
Long-term revolving credit 475 — 
Senior secured notes 166 55 
First mortgage bonds 7 —  14 — 
Pollution control notes 251 687 
Senior secured notes 63 54 
Unsecured notes 101 1,472  35 100 
          
 $422 $2,213  $1,002 $406 
          
  
Short-term borrowings, net $(171) $(764) $(44) $281 
          
In 2011, FES paid off at maturity a $100 million term loan that was secured by FMBs. In April 2011, FirstEnergy entered into a $150 million unsecured term loan with an April 2013 maturity.

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In 2011 FES repurchased and retired $20 million of its 6.80% unsecured senior notes and $15 million of its 6.05% unsecured senior notes. In April 2011, Met-Ed redeemed approximately $14 million of FMBs securing PCRBs.
During the remainder of 2011 FirstEnergy and its subsidiaries expect to pursue, from time to time, continued reductions in outstanding long-term debt of up to approximately $1.0 to $1.5 billion through redemptions, open market or privately negotiated purchases. Any such transactions will be subject to prevailing market conditions, liquidity requirements, timing of asset sales and other factors.
Cash Flows From Investing Activities
Net cash flowsCash used infor investing activities in the first six months of 2011 resulted primarily from cash used for property additions. Additions for the energy delivery services segment primarily represent expenditures related to transmission and distribution facilities. Capital spendingadditions, partially offset by the competitive energy services segment is principally generation-related.cash acquired in the Allegheny merger. The following table summarizes investing activities for the first ninesix months of 20102011 and 2009the comparable period of 2010 by business segment:
                 
Summary of Cash Flows Property          
Provided from (Used for) Investing Activities Additions  Investments  Other  Total 
      (In millions)     
Sources (Uses)
                
Nine Months Ended September 30, 2010
                
Energy delivery services $(546) $82  $11  $(453)
Competitive energy services  (860)  (26)  (53)  (939)
Other  (18)  (3)  34   13 
Inter-Segment reconciling items  (43)  (23)  —   (66)
             
Total $(1,467) $30  $(8) $(1,445)
             
                 
Nine Months Ended September 30, 2009
                
Energy delivery services $(524) $(121) $(35) $(680)
Competitive energy services  (893)  (6)  (21)  (920)
Other  (133)      (11)  (144)
Inter-Segment reconciling items  (25)  (25)  6   (44)
             
Total $(1,575) $(152) $(61) $(1,788)
             
                 
Summary of Cash Flows Property          
Provided from (Used for) Investing Activities Additions  Investments  Other  Total 
  (In millions) 
Sources (Uses)
                
Six Months Ended June 30, 2011
                
Regulated distribution $(479) $(2) $(25) $(506)
Competitive energy services  (411)  (32)  (335)  (778)
Regulated independent transmission  (72)  (1)  (1)  (74)
Cash received in Allegheny merger  —   590   —   590 
Other and reconciling items  (56)  (21)  310   233 
             
Total $(1,018) $534  $(51) $(535)
             
                 
Six Months Ended June 30, 2010
                
Regulated distribution $(309) $87  $(18) $(240)
Competitive energy services  (619)  (11)  (1)  (631)
Regulated independent transmission  (29)  —   (2)  (31)
Other and reconciling items  (40)  (25)  —   (65)
             
Total $(997) $51  $(21) $(967)
             

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Net cash used forin investing activities induring the first ninesix months of 20102011 decreased by $343$432 million compared to the first nine monthssame period of 2009.2010. The decrease was principally due to a $108 million decreasecash acquired in property additions (principally lower AQC system expenditures) and an increase in cash proceeds from the sale of assets of $98 million,Allegheny merger ($590 million), partially offset by $110 million spent by FESa decrease in the customer acquisition process.net proceeds from asset sales and higher property additions ($137 million).
During the remaining quartersecond half of 2010,2011, capital requirements for property additions and capital leases are expected to be approximately $410 million,$1.2 billion, including approximately $32$122 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 SeptemberJune 30, 2010,2011, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $3.8 billion, as summarized below:
        
 Maximum  Maximum 
Guarantees and Other Assurances Exposure  Exposure 
 (In millions)  (In millions) 
FirstEnergy Guarantees on Behalf of its Subsidiaries  
Energy and Energy-Related Contracts(1)
 $300  $223 
LOC (long-term debt) —Interest coverage(2)
 6 
FirstEnergy guarantee of OVEC obligations 300 
Other(3)
 226 
OVEC obligations 300 
Other(2)
 301 
      
 832  824 
      
  
Subsidiaries’ Guarantees  
Energy and Energy-Related Contracts 54  155 
LOC (long-term debt) —Interest coverage(2)
 4 
FES’ guarantee of NGC’s nuclear property insurance 70  70 
FES’ guarantee of FGCO’s sale and leaseback obligations 2,413  2,324 
Other 2  19 
      
 2,543  2,568 
      
  
Surety Bonds 84  136 
LOC (long-term debt) — Interest coverage(2)
 3 
LOC (non-debt)(4)(5)
 380 
LOC(3)
 269 
      
 467  405 
      
Total Guarantees and Other Assurances $3,842  $3,797 
      
   
(1) Issued for open-ended terms, with a 10-day termination right by FirstEnergy.
 
(2) Reflects the interest coverage portion of LOCs issued in support of floating rate PCRBs with various maturities. The principal amount of floating-rate PCRBs of $1.3 billion is reflected in currently payable long-term debt on FirstEnergy’s consolidated balance sheets.
(3)Includes guarantees of $15$95 million for nuclear decommissioning funding assurances, $161 million supporting OE’s sale and leaseback arrangement, and $34$35 million for railcar leases.
 
(4)(3) Includes $201$105 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facility.
(5)Includes approximately $135facilities, $122 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $44$39 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’sother FirstEnergy assets. FirstEnergy believes the likelihood is remote that such parental guarantees will increase amounts otherwise paid by FirstEnergy to meet its obligations incurred in connection with ongoing energy and energy-related activities.
While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade to below investment grade, an acceleration or funding obligation or a “material adverse event,” the immediate posting of cash collateral, provision of aan LOC or accelerated payments may be required of the subsidiary. As of SeptemberJune 30, 2010,2011, FirstEnergy’s maximum exposure under these collateral provisions was $419$625 million, as shown below:
                            
Collateral Provisions FES Utilities Total  FES AE Supply Utilities Total 
 (In millions)  (In millions) 
Credit rating downgrade to below investment grade (1)
 $306 $68 $374  $440 $4 $78 $522 
Material adverse event (2)
 45 — 45  33 57 13 103 
                
Total $351 $68 $419  $473 $61 $91 $625 
                
   
(1) Includes $85$206 million and $57$59 million that is also considered an acceleration of payment or funding obligation atfor FES and the Utilities, respectively.
 
(2) Includes $33$32 million that is also considered an acceleration of payment or funding obligation atfor FES.

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Stress case conditions of a credit rating downgrade or “material adverse event” and hypothetical adverse price movements in the underlying commodity markets would increase the total potential amount to $511$666 million, consisting of $463 million due to a below investment grade credit rating, of which $175 million is related to an acceleration of payment or funding obligation, and $48 million due to “material adverse event” contractual clauses.as shown below:
                 
Collateral Provisions FES  AE Supply  Utilities  Total 
  (In millions) 
Credit rating downgrade to below investment grade (1)
 $477  $5  $78  $560 
Material adverse event (2)
  36   57   13   106 
             
Total $513  $62  $91  $666 
             
(1)Includes $206 million and $59 million that is also considered an acceleration of payment or funding obligation for FES and the Utilities, respectively.
(2)Includes $32 million that is also considered an acceleration of payment or funding obligation for FES.
Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $84$136 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.
In addition to guarantees and surety bonds, FES’ contracts entered into by the Competitive Energy Services segment, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions whichthat require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ and AE Supply’s power portfolioportfolios as of SeptemberJune 30, 2010,2011 and forward prices as of that date, FES hasand AE Supply have posted collateral of $244 million.$138 million and $2 million, respectively. Under a hypothetical adverse change in forward prices (95% confidence level change in forward prices over a one yearone-year time horizon), FES would be required to post an additional $46 million.$17 million of collateral. Depending on the volume of forward contracts and future price movements, FEShigher amounts for margining could be required to post higher amounts for margining.
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.be posted.
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 willwould have claims against each of FES, FGCO and NGC, regardless of whether their primary obligor is FES, FGCO or NGC.
On October 22, 2010, Signal Peak and Global Rail entered intoare borrowers under a $350 million syndicated two-year senior secured term loan facility among the two limited liability companies that comprise Signal Peak and Global Rail, as borrowers, Sovereign Bank, CoBank, Credit Agricole, U.S. Bank, BBVA Compass, Royal Bank of Canada, Fifth Third, Comerica Bank, CIBC Inc. and First Merit banks, as lenders, and Union Bank, N.A. as lender, administrative agent, collateral agent and syndication agent.due in October 2012. FirstEnergy, together with WMB Loan Ventures LLC and WMB Loan Ventures II LLC, the entities that share ownership with FEV in the borrowers with FEV, have provided a guaranty of the borrowers’ obligations under the facility. In addition, FEV and the other entities that directly own the equity interestsinterest in the borrowers have pledged those interests to the bankslenders under the term loan facility as collateral for the facility.

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OFF-BALANCE SHEET ARRANGEMENTS
FES and the Ohio Companies have obligations that are not included on their Consolidated Balance Sheets related to sale and leaseback arrangements involving the Bruce Mansfield Plant, Perry Unit 1 and Beaver Valley Unit 2, which are satisfied through operating lease payments. The total present value of these sale and leaseback operating lease commitments, net of trust investments, is $1.7was $1.6 billion as of SeptemberJune 30, 2010.
2011.
MARKET RISK INFORMATION
FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.
Commodity Price Risk
FirstEnergy is exposed to financial and market risks resulting from the fluctuation offluctuating interest rates and commodity prices, associated withincluding prices for electricity, energy transmission, natural gas, coal nuclear fuel and emission allowances.energy transmission. To manage the volatility relating to these exposures, FirstEnergy established a Risk Policy Committee, comprised of members of senior management, which provides general management oversight for risk management activities throughout FirstEnergy. The Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. FirstEnergy uses a variety of non-derivative and derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps. TheIn addition to derivatives, are used principally for hedging purposes.FirstEnergy also enters into master netting agreements with certain third parties.

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The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, FirstEnergy relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FirstEnergy uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making (see Note 5 to the consolidated financial statements). Sources of information for the valuation of commodity derivative contracts as of SeptemberJune 30, 20102011 are summarized by year in the following table:
                                                        
Source of Information-                              
Fair Value by Contract Year 2010 2011 2012 2013 2014 Thereafter Total  2011 2012 2013 2014 2015 Thereafter Total 
 (In millions)  (In millions) 
Prices actively quoted(1)
 $(2) $— $— $— $— $— $(2) $— $— $— $— $— $— $— 
Other external sources(2)
  (328)  (369)  (164)  (53) 7  (10)  (917)  (287)  (169)  (48)  (38) — —  (542)
Prices based on models — — — —  (9) 141 132  9  (3) — — — 44 50 
                              
Total(3)
 $(330) $(369) $(164) $(53) $(2) $131 $(787) $(278) $(172) $(48) $(38) $— $44 $(492)
                              
   
(1) Represents exchange traded New York Mercantile Exchange futures and options.
 
(2) Primarily represents contracts based on broker and IntercontinentalExchange quotes.
 
(3) Includes $629$445 million in non-hedge commodity derivative contracts that are primarily related to NUG contracts. NUG contracts are generally subject to regulatory accounting and do not materially impact earnings.
FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. Based on derivative contracts held as of SeptemberJune 30, 2010,2011, an adverse 10% change in commodity prices would decrease net income by approximately $6$31 million ($420 million net of tax) during the next 12 months.
Interest Rate Swap Agreements — Fair Value Hedges
FirstEnergy has used fixed-for-floating interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with the debt portfolio of its subsidiaries. These derivatives were treated as fair value hedges of fixed-rate, long-term debt issues, protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. As of September 30, 2010, no fixed-for-floating interest rate swap agreements were outstanding.
Total unamortized gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements totaled $129 million ($84 million net of tax) as of September 30, 2010. Based on current estimates, approximately $22 million will be amortized to interest expense during the next twelve months. Reclassifications from long-term debt into interest expense totaled $5 million and $7 million for the three and nine months ended September 30, 2010.
Equity Price Risk
FirstEnergy provides a noncontributory qualified defined benefit pension planplans that coverscover substantially all of its employees and non-qualified pension plans that cover certain employees. The plan providesplans provide defined benefits based on years of service and compensation levels.
FirstEnergy also provides healtha portion of non-contributory pre-retirement basic life insurance for employees who are eligible to retire. Health care benefits, (whichwhich include certain employee contributions, deductibles and co-payments)co-payments, are also available upon retirement to certain employees, hired prior to January 1, 2005, their dependents and, under certain circumstances, their survivors. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.
The benefit plan assets and obligations are remeasured annually using a December 31 measurement date or as significant triggering events occur. As of SeptemberJune 30, 2010, approximately 44% of2011, the FirstEnergy pension plan assets arewas invested in approximately 31% of equity securities, and 56% are invested in46% of fixed income securities. The plan is 81% funded on an accumulated benefit obligation basis assecurities, 9% of September 30, 2010.absolute return strategies, 6% of real estate, 4% of private equity and 4% of cash. A decline in the value of FirstEnergy’s pension plan assets could result in additional funding requirements. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. During the three months and six months ended June 30, 2011, FirstEnergy currently estimates thatmade contributions to its qualified pension plans of $105 million and $262 million, respectively. FirstEnergy intends to make additional cash contributions will be required beginningof $116 million and $2 million to its qualified pension plans and postretirement benefit plans, respectively, in 2012.the last two quarters of 2011.

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Nuclear decommissioning trustNDT funds have been established to satisfy NGC’s and the Utilities’ nuclear decommissioning obligations. As of SeptemberJune 30, 2010,2011, approximately 15%87% of the funds were invested in fixed income securities, 10% of the funds were invested in equity securities and 85%3% were invested in fixed income securities,short-term investments, with limitations related to concentration and investment grade ratings. The equity securitiesinvestments are carried at their market valuevalues of approximately $305$1,779 million, $197 million and $69 million for fixed income securities, equity securities and short-term investments, respectively, as of SeptemberJune 30, 2010.2011, excluding $6 million of receivables, payables, deferred taxes and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $31$20 million reduction in fair value as of SeptemberJune 30, 2010.2011. The decommissioning trusts of JCP&L and the Pennsylvania Companies are subject to regulatory accounting, with unrealized gains and losses recorded as regulatory assets or liabilities, since the difference between investments held in trust and the decommissioning liabilities will be recovered from or refunded to customers. NGC, OE and TE recognize in earnings the unrealized losses on available-for-sale securities held in their nuclear decommissioning trustsNDT as other-than-temporary impairments. A decline in the value of FirstEnergy’s nuclearNDT or a significant escalation in estimated decommissioning trustscosts could result in additional funding requirements. During 2010,the first six months of 2011, approximately $1 million, $4 million and $1 million was contributed to theNDT of JCP&L, OE and TE, respectively. On March 28, 2011, FENOC submitted its biennial report on nuclear decommissioning trusts to comply with requirements under certain sale-leaseback transactions in which OE and TE continue as lessees, and $4 million was contributedfunding to the JCP&L and PennsylvaniaNRC. This submittal identified a total shortfall in nuclear decommissioning trusts to comply with regulatory requirements. FirstEnergy continues to evaluate the statusfunding for Beaver Valley Unit 1 and Perry of its funding obligations for the decommissioning of these nuclear facilities and does not expect to make additional cash contributions$92 million. On June 24, 2011, FENOC submitted a $95 million parental guarantee to the nuclear decommissioning trustsNRC for the remainder of 2010 other than those to the JCP&L and Pennsylvania Companies’ nuclear decommissioning trusts due to regulatory requirements.its approval.
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.

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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 SeptemberJune 30, 2010,2011, the largest credit concentration was with J.P. Morgan Chase & Co., which is currently rated investment grade, representing 9.42%11% of FirstEnergy’s total approved credit risk.
risk comprised of 2.4% for FES, 1.6% for JCP&L, 2.0% for Met-Ed, 3.4% for WP and a combined 2.0% for the Ohio Companies.
OUTLOOK
Reliability Initiatives
Federally-enforceable mandatory reliability standards apply to the bulk powerelectric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES, FGCO, FENOC, ATSI and ATSI.TrAIL. The NERC is the ERO charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including ReliabilityFirstCorporation. All of FirstEnergy’s facilities are located within the ReliabilityFirstregion. FirstEnergy actively participates in the NERC and ReliabilityFirststakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by the ReliabilityFirstCorporation.
FirstEnergy believes that it generally is in compliance with all currently-effective and enforceable reliability standards. FirstEnergy’s practice is to address and resolve any occasional or isolated incidents of noncompliance as they ariseNevertheless, in the normal course of operations.operating its extensive electric utility systems and facilities, FirstEnergy also believesoccasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such items are found, FirstEnergy develops information about the item and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an item to ReliabilityFirst. Moreover, it is clear that the NERC, ReliabilityFirstand the FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with future new or amended standards cannot be determined at this time; however, 2005 amendments to the FPA provide that all prudent costs incurred to comply with the newfuture reliability standards be recovered in rates. Still, any future inability on FirstEnergy’s part to comply with the reliability standards for its bulk power system could result in the imposition of financial penalties that could have a material adverse effect on its financial condition, results of operations and cash flows.
On December 9, 2008, a transformer at JCP&L’s Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission voltage) lines out of the Oceanview and Atlantic substations resulting in customers losing power for up to eleven hours. On March 31, 2009, the NERC initiated a Compliance Violation Investigation in order to determine JCP&L’s contribution to the electrical event and to review any potential violation of NERC Reliability Standards associated with the event. NERC has submitted first and second Requests for Information regarding this and another related matter. JCP&L is complying with these requests. JCP&L is not able to predict what actions, if any, that the NERC may take with respect to this matter.

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On August 23, 2010, FirstEnergy self-reported to ReliabilityFirsta vegetation encroachment event on a Met-Ed 230 kV line to ReliabilityFirst.line. This event did not result in a fault, outage, operation of protective equipment, or any other meaningful electric effect on any FirstEnergy transmission facilities or systems. On August 25, 2010, ReliabilityFirstissued a Notice of Enforcement to investigate the incident. FirstEnergy submitted a data response to ReliabilityFirston September 27, 2010. 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,In March 2011, ReliabilityFirstsubmitted its proposed findings and provides for generation supplied throughsettlement, although a CBP. The Amended ESP also allows the Ohio Companies to collect a delivery service improvement rider (Rider DSI) at an overall average rate of $0.002 per KWH for the period of April 1, 2009 through December 31, 2011. The Ohio Companies currently purchase generation at the average wholesale rate of a CBP conducted in May 2009. FES is one of the suppliers to the Ohio Companies through the May 2009 CBP. The PUCO approved a $136.6 million distribution rate increase for the Ohio Companies in January 2009, which went into effect on January 23, 2009 for OE ($68.9 million) and TE ($38.5 million) and on May 1, 2009 for CEI ($29.2 million). Applications for rehearing of the PUCO order in the distribution case were filed by the Ohio Companies and one other party. The Ohio Companies raised numerous issues in their application for rehearing related to rate recovery of certain expenses, recovery of line extension costs, the level of rate of return and the amount of general plant balances. The PUCOfinal determination has not yet issuedbeen made by FERC.
Allegheny has been subject to routine audits with respect to its compliance with applicable reliability standards and has settled certain related issues. In addition, ReliabilityFirstis currently conducting certain investigations with regard to certain matters of compliance by Allegheny.
Maryland
By statute enacted in 2007, the obligation of Maryland utilities to provide standard offer service (SOS) to residential and small commercial customers, in exchange for recovery of their costs plus a substantive Entryreasonable profit, was extended indefinitely. The legislation also established a five-year cycle (to begin in 2008) for the MDPSC to report to the legislature on Rehearing.
On October 20, 2009, the Ohio Companies filed an MROstatus of SOS. PE now conducts rolling auctions to procure throughthe power supply necessary to serve its customer load pursuant to a CBP,plan approved by the MDPSC. However, the terms on which PE will provide SOS to residential customers after the settlement beyond 2012 will depend on developments with respect to SOS in Maryland between now and then, including but not limited to possible MDPSC decisions in the proceedings discussed below.
The MDPSC opened a new docket in August 2007 to consider matters relating to possible “managed portfolio” approaches to SOS and other matters. “Phase II” of the case addressed utility purchases or construction of generation, supplybidding for customers who do not shop with an alternative supplier forprocurement of demand response resources and possible alternatives if the period beginning June 1, 2011. The CBP would be similar, in all material respects, toTrAIL and PATH projects were delayed or defeated. It is unclear when the CBP conducted in May 2009 in that it would procure energy, capacity and certain transmission services on a slice of system basis. However, unlike the May 2009 CBP, the MRO would include multiple bidding sessions and multiple products with different delivery periods for generation supply designed to reduce potential volatility and supplier risk and encourage bidder participation. Although the Ohio Companies requested a PUCO determination by January 18, 2010, on February 3, 2010, the PUCO announced thatMDPSC will issue its determination would be delayed. The PUCO has not yet issued an orderfindings in this matter.
On March 23, 2010, the Ohio Companies filed an application for a new ESP. The new ESP will go into effect on June 1, 2011 and conclude on May 31, 2014. Attached to the application was a Stipulation and Recommendation signed by the Ohio Companies, the Staff of the PUCO, and an additional fourteen parties signing as Signatory Parties, with two additional parties agreeing not to oppose the adoption of the Stipulation. The material terms of the Stipulation include a CBP similar to the one used in May 2009 and the one proposed in the October 2009 MRO filing; a 6% generation discount to certain low-income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (initial auctions scheduled for October 20, 2010 and January 25, 2011); no increase in base distribution rates through May 31, 2014; load cap of no less than 80%, which also applies to any tranches assigned post auction; and a new distribution rider, Delivery Capital Recovery Rider (Rider DCR), to recover a return of, and on, capital investments in the delivery system. This Rider substitutes for Rider DSI which terminates by its own terms. The Ohio Companies also agree not to collect certain amounts associated with RTEP and administrative costs associated with the move to PJM, dependent on the outcome of certain PJM proceedings. Many of the existing riders approved in the previous ESP remain in effect, some with modifications. The new ESP also requests the resolution of current proceedings pending at the PUCO regarding corporate separation, elements of the smart grid proceeding and the move to PJM. FirstEnergy recorded approximately $39.5 million of regulatory asset impairments and expenses related to the ESP. On May 12, 2010, a supplemental stipulation was filed that added two additional parties to the Stipulation, namely the City of Akron, Ohio and Council for Smaller Enterprises, to provide additional energy efficiency benefits. On July 22, 2010, a second supplemental stipulation was filed that, among other provisions provides a commitment that retail customers of the Ohio Companies will not pay certain costs related to the companies’ integration into PJM, for the longer of the five year period from June 1, 2011 through May 31, 2016 or when the amount of costs avoided by customers for certain types of products totals $360 million dependent on the outcome of certain PJM proceedings, and establishes a $12 million fund to assist low income customers over the term of the ESP. Additional parties signing or not opposing the second supplemental stipulation include Northeast Ohio Public Energy Council (NOPEC), Northwest Ohio Aggregation Coalition (NOAC), Environmental Law and Policy Center and a number of low income community agencies. The PUCO modified and approved the new ESP on August 25, 2010. The Companies accepted the PUCO’s decision subject to the implementation of certain elements of the ESP being consistent with the terms as they were included in the stipulation. On September 24, 2010, an application for rehearing was filed by the OCC and two other parties. The Ohio Companies and other parties filed their memorandum contra to that application for rehearing on October 4, 2010. The PUCO granted the application for rehearing on October 22, 2010. The PUCO has yet to rule on the substance of the application for rehearing.
Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total annual energy savings equivalent of approximately 166,000 MWH in 2009, 290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in 2012 and 530,000 MWH in 2013, with additional savings required through 2025. Utilities are also required to reduce peak demand in 2009 by 1%, with an additional 0.75% reduction each year thereafter through 2018. The Ohio Companies filed an application with the PUCO seeking amendments to these benchmarks. On January 7, 2010, the PUCO amended the Ohio Companies’ 2009 energy efficiency benchmarks to zero, contingent upon the Ohio Companies meeting the revised benchmarks in a period of not more than three years. On March 10, 2010, the PUCO found that the Ohio Companies’ peak demand reduction programs complied with PUCO rules.SOS-related pending proceedings discussed below.

 

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On December 15,In September 2009, the Ohio CompaniesMDPSC opened a new proceeding to receive and consider proposals for construction of new generation resources in Maryland. In December 2009, Governor Martin O’Malley filed a letter in this proceeding in which he characterized the electricity market in Maryland as a “failure” and urged the MDPSC to use its existing authority to order the construction of new generation in Maryland, vary the means used by utilities to procure generation and include more renewables in the generation mix. In August 2010, the MDPSC opened another new proceeding to solicit comments on the PJM RPM process. Public hearings on the comments were held in October 2010. In December 2010, the MDPSC issued an order soliciting comments on a model request for proposal for solicitation of long-term energy commitments by Maryland electric utilities. PE and numerous other parties filed comments, and at this time no further proceedings have been set by the MDPSC in this matter.
In September 2007, the MDPSC issued an order that required three year portfolio plan seeking approvalthe Maryland utilities to file detailed plans for how they will meet the “EmPOWER Maryland” proposal that electric consumption be reduced by 10% and electricity demand be reduced by 15%, in each case by 2015.
The Maryland legislature in 2008 adopted a statute codifying the EmPOWER Maryland goals. In 2008, PE filed its comprehensive plans for attempting to achieve those goals, asking the MDPSC to approve programs for residential, commercial, industrial, and governmental customers, as well as a customer education program. The MDPSC ultimately approved the programs in August 2009 after certain modifications had been made as required by the MDPSC, and approved cost recovery for the programs they intendin October 2009. Expenditures were estimated to implementbe approximately $101 million and would be recovered over the following six years. Meanwhile, extensive meetings with the MDPSC Staff and other stakeholders to meet the energy efficiencydiscuss details of PE’s plans for additional and peak demand reduction requirementsimproved programs for the 2010-2012 period. period 2012-2014 began in April 2011 and those programs are to be filed by September 1, 2011.
In March 2009, the MDPSC issued an order suspending until further notice the right of all electric and gas utilities in the state to terminate service to residential customers for non-payment of bills. The MDPSC subsequently issued an order making various rule changes relating to terminations, payment plans, and customer deposits that make it more difficult for Maryland utilities to collect deposits or to terminate service for non-payment. The MDPSC is continuing to conduct hearings and collect data on payment plan and related issues and has adopted a set of proposed regulations that expand the summer and winter “severe weather” termination moratoria when temperatures are very high or very low, from one day, as provided by statute, to three days on each occurrence.
On March 8, 2010,24, 2011, the Ohio CompaniesMDPSC held an initial hearing to discuss possible new regulations relating to service interruptions, storm response, call center metrics, and related reliability standards. The proposed rules included provisions for civil penalties for non-compliance. Numerous parties filed their 2009 Status Update Reportcomments on the proposed rules and participated in the hearing, with many noting issues of cost and practicality relating to implementation. The Maryland legislature passed a bill on April 11, 2011, which requires the PUCOMDPSC to promulgate rules by July 1, 2012 that address service interruptions, downed wire response, customer communication, vegetation management, equipment inspection, and annual reporting. In crafting the regulations, the legislation directs the MDPSC to consider cost-effectiveness, and provides that the MDPSC may adopt different standards for different utilities based on such factors as system design and existing infrastructure, geography, and customer density. Beginning in which they indicatedJuly 2013, the MDPSC is to assess each utility’s compliance with the 2009 statutory energy efficiencystandards, and peak demand benchmarks as those benchmarks were amended as described above.may assess penalties of up to $25,000 per day per violation. The Ohio Companies expectMDPSC has ordered that all costs associateda working group of utilities, regulators, and other interested stakeholders meet to address the topics of the proposed rules, with compliance will be recoverable from customers. The Ohio Companies’ three year portfolio plan is still awaiting decision from the PUCO. The plan has yetproposed rules to be approvedfiled by September 15, 2011. Separately, on April 7, 2011, the PUCO, which is delayingMDPSC initiated a rulemaking with respect to issues related to contact voltage. On June 3, 2011, the launch of the programs described in the plan. Without such approval, the Ohio Companies’ compliance with 2010 benchmarks is jeopardized and if not approved soon may require the Ohio Companies to seek an amendment to their annual benchmark requirements for 2010. Failure to comply with the benchmarks or to obtain such an amendment may subject the Companies to an assessment by the PUCO of a forfeiture.
Additionally under SB221, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they served in 2009. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RFPs sought RECs, including solar RECs and RECs generated in Ohio in order to meet the Ohio Companies’ alternative energy requirements as set forth in SB221 for 2009, 2010 and 2011. The RECs acquired through these two RFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. On March 10, 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market. The PUCO reduced the Ohio Companies’ aggregate 2009 benchmark to the level of solar RECs the Ohio Companies acquired through their 2009 RFP processes, provided the Ohio Companies’ 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC benchmark. On April 15, 2010, the Ohio Companies and FES (due to its status as an electric service company in Ohio) filed compliance reports with the PUCO setting forth how they individually satisfied the alternative energy requirements in SB221 for 2009. FES also applied for a force majeure determination from the PUCO regarding a portion of their compliance with the 2009 solar energy resource benchmark, which application is still pending. In July 2010, the Ohio Companies initiated an additional RFP to secure RECs and solar RECs needed to meet the Ohio Companies’ alternative energy requirements as set forth in SB221. As a result of this RFP, contracts were executed in August 2010.
On February 12, 2010, OE and CEI filed an application with the PUCO to establish a new credit for all-electric customers. On March 3, 2010, the PUCO ordered that rates for the affected customers be set at a level that will provide bill impacts commensurate with charges in place on December 31, 2008 and authorized the Ohio Companies to defer incurred costs equivalent to the difference between what the affected customers would have paid under previously existing rates and what they pay with the new credit in place. Tariffs implementing this new credit went into effect on March 17, 2010. On April 15, 2010, the PUCO issued a Second Entry on Rehearing that expanded the group of customers to which the new credit would apply and authorized deferral for the associated additional amounts. The PUCO also stated that it expected that the new credit would remain in place through at least the 2011 winter season, and charged its staff to work with parties to seek a long term solution to the issue. Tariffs implementing this newly expanded credit went into effect on May 21, 2010. The Ohio Companies also filed on May 14, 2010 an application for rehearing of the Second Entry on Rehearing, which was granted for purposes of further consideration on June 9, 2010. On September 9, 2010, the OCC filed a motion requesting that a procedural schedule be established. The Ohio Companies filed their motion contra on September 23, 2010. The PUCOMDPSC’s Staff issued a report and draft regulations. Comments on the draft regulations were submitted on June 17, 2011, and a hearing was held July 7, 2011. Final regulations related to the all-electric issue on September 24, 2010, in which it provides background on the issue and sets forth its bill impact analysis under a number of different scenarios for a longer term solution, but it made no specific recommendation to the PUCO.contact voltage have not yet been adopted.
Pennsylvania
Met-Ed and Penelec purchase a portion of their POLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy sold to the extent needed for Met-Ed and Penelec to satisfy their POLR and default service obligations.
Met-Ed and Penelec filed with the PPUC a generation procurement plan covering the period January 1, 2011 through May 31, 2013. The plan is designed to provide adequate and reliable service via a prudent mix of long-term, short-term and spot market generation supply, as required by Act 129, with a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. On August 12, 2009, Met-Ed and Penelec filed a settlement agreement with the PPUC for the generation procurement plan, reflecting the settlement on all but two reserved issues. On November 6, 2009, the PPUC entered an Order approving the settlement and finding in favor of Met-Ed and Penelec on the two reserved issues. Generation procurement began in January 2010.

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On February 8, 2010, Penn filed a Petition for Approval of its Default Service Plan for the period June 1, 2011 through May 31, 2013. On July 29, 2010, the parties to the proceeding filed a Joint Petition for Settlement of all issues. The PPUC adopted a Motion approving the Joint Petition for Settlement on October 21, 2010. The Joint Petition resolves all issues relating to Penn’s Default Service Plan for the next program period, including its procurement method, compliance with the Alternative Energy Portfolio Standards Act, rate design and retail market issues. The PPUC’s approval of the Joint Petition is conditioned by holding that the provision relating to the recovery of MISO exit cost fees and one-time PJM integration costs (resulting from Penn’s June 1, 2011 exit of MISO and integration into PJM) be approved, but made subject to the approval of cost recovery by FERC. Penn may not put these provisions into effect until FERC has approved the recovery and allocation of MISO exit fees and PJM integration costs. An Order consistent with the Motion is expected to be entered in the near future.
The PPUC adopted a Motion on January 28, 2010 and subsequently entered an Order on March 3, 2010 which denies the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, and directs Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructs Met-Ed and Penelec to work with the various intervening parties to file a recommendation to the PPUC regarding the establishment of a separate account for all marginal transmission losses collected from ratepayers plus interest to be used to mitigate future generation rate increases beginning January 1, 2011. On March 18, 2010, Met-Ed and Penelec filed a Petition with the PPUC requesting that it stay the portion of the March 3, 2010 Order requiring the filing of tariff supplements to end collection of costs for marginal transmission losses. By Order entered March 25, 2010, the PPUC granted the requested stay until December 31, 2010. Pursuant to the PPUC’s order, Met-Ed and Penelec filed the plan to establish separate accounts for marginal transmission loss revenues and related interest and carrying charges and the plan for the use of these funds to mitigate future generation rate increases commencing January 1, 2011. The PPUC approved this plan on June 7, 2010. On April 1, 2010, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania appealing the PPUC’s March 3, 2010 Order. Although the ultimate outcome of this matter cannot be determined at this time, it is the belief of Met-Ed and Penelec that they should prevail in the appeal and therefore expect to fully recover the approximately $199.7 million ($158.5 million for Met-Ed and $41.2 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011. On July 9, 2010, Met-Ed and Penelec filed their briefs with the Commonwealth Court of Pennsylvania. The Office of Small Business Advocate filed its brief on July 9, 2010. On August 24, 2010, the PPUC as well as MEIUG and PICA filed their briefs. Met-Ed and Penelec filed their reply brief on September 9, 2010.
On May 20, 2010, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider for the period June 1, 2010 through December 31, 2010 including marginal transmission losses as approved by the PPUC, although the recovery of marginal losses will be subject to the outcome of the proceeding related to the 2008 TSC filing as described above. The TSC for Met-Ed’s customers was increased to provide for full recovery by December 31, 2010.
Act 129 was enacted in 2008 to address issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters; and alternative energy. Among other things, Act 129 required utilities to file with the PPUC an energy efficiency and peak load reduction plan, or EE&C Plan, by July 1, 2009, setting forth the utilities’ plans to reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of 4.5% by May 31, 2013. The PPUC entered an Order on February 26, 2010 approving the Pennsylvania Companies’ EE&C Plans and the tariff rider with rates effective March 1, 2010.
Met-Ed, Penelec and Penn jointly filed a Smart Meter Technology Procurement and Installation Plan with the PPUC. This plan proposes a 24-month assessment period in which the Pennsylvania Companies will assess their needs, select the necessary technology, secure vendors, train personnel, install and test support equipment, and establish a cost effective and strategic deployment schedule, which currently is expected to be completed in fifteen years. Met-Ed, Penelec and Penn estimate assessment period costs at approximately $29.5 million, which the Pennsylvania Companies, in their plan, proposed to recover through an automatic adjustment clause. The ALJ’s Initial Decision approved the Smart Meter Plan as modified by the ALJ, including: ensuring that the smart meters to be deployed include the capabilities listed in the PPUC’s Implementation Order; eliminating the provision of interest in the 1307(e) reconciliation; providing for the recovery of reasonable and prudent costs minus resulting savings from installation and use of smart meters; and reflecting that administrative start-up costs be expensed and the costs incurred for research and development in the assessment period be capitalized. On April 15, 2010, the PPUC adopted a Motion by Chairman Cawley that modified the ALJ’s initial decision, and decided various issues regarding the Smart Meter Implementation Plan for the Pennsylvania Companies. The PPUC entered its Order on June 9, 2010, consistent with the Chairman’s Motion. On June 24, 2010, Met-Ed, Penelec and Penn filed a Petition for Reconsideration of a single portion of the PPUC’s Order regarding the future ability to include smart meter costs in base rates. On August 5, 2010, the PPUC granted in part the petition for reconsideration by deleting language from its original order that would have precluded Met-Ed, Penelec and Penn from seeking to include smart meter costs in base rates at a later time.
By Tentative Order entered September 17, 2009, the PPUC provided for an additional 30-day comment period on whether the 1998 Restructuring Settlement allows Met-Ed and Penelec to apply over-collection of NUG costs for select and isolated months to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists. In response to the Tentative Order, various parties filed comments objecting to the above accounting method utilized by Met-Ed and Penelec. Met-Ed and Penelec are awaiting further action by the PPUC.

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New Jersey
JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers, costs incurred under NUG agreements,In March 2009 and certain other stranded costs, exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of September 30, 2010, the accumulated deferred cost balance was a credit of approximately $3 million. To better align the recovery of expected costs, on July 26,again in February 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 PetitionPetitions with the NJBPU that includesincluded a request for a reduction in therequested zero level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009 estimated at $736 million (in 2003 dollars). This matter is currently pending beforeIn its order of June 15, 2011, 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 establishinga Stipulation reached among JCP&L, the general processNJBPU Staff and contentsthe Division of specific EMP plans that must be filed by New Jersey electric and gas utilitiesRate Counsel which resolved both Petitions, resulting in order to achieve the goalsa net reduction in recovery of $0.8 million annually for all components of the EMP. On April 16, 2010, the NJBPU issuedSBC (including, as requested, a zero level of recovery of TMI-2 decommissioning costs).
Ohio
The Ohio Companies operate under an order indefinitely suspending the requirement of New Jersey utilities to submit Utility Master Plans until such time as the statusESP, which expires on May 31, 2014. The material terms of the EMP has been made clear. At this time, FirstEnergyESP include: generation supplied through a CBP commencing June 1, 2011 (initial auctions held on October 20, 2010 and JCP&L cannot determineJanuary 25, 2011); a load cap of no less than 80%, which also applies to tranches assigned post-auction; a 6% generation discount to certain low income customers provided by the impact, if any,Ohio Companies through a bilateral wholesale contract with FES (FES is one of the EMP may havewholesale suppliers to the Ohio Companies); no increase in base distribution rates through May 31, 2014; and a new distribution rider, Delivery Capital Recovery Rider (Rider DCR), to recover a return of, and on, their operations.
In supportcapital investments in the delivery system. The Ohio Companies also agreed not to recover from retail customers certain costs related to transmission cost allocations by PJM as a result of former New Jersey Governor Corzine’s Economic AssistanceATSI’s integration into PJM for the longer of the five-year period from June 1, 2011 through May 31, 2015 or when the amount of costs avoided by customers for certain types of products totals $360 million dependent on the outcome of certain PJM proceedings, agreed to establish a $12 million fund to assist low income customers over the term of the ESP and Recovery Plan, JCP&L announced a proposalagreed to spend approximately $98 million on infrastructure andadditional matters related to energy efficiency projects in 2009. and alternative energy requirements.

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Under the proposal, an estimated $40 million would be spent on infrastructure projects, including substation upgrades, new transformers, distribution line re-closers and automated breaker operations. In addition, approximately $34 million would be spent implementing new demand response programs as well as expanding on existing programs. Another $11 million would be spent on energy efficiency, specifically replacing transformers and capacitor control systems and installing new LED street lights. The remaining $13 million would be spent onprovisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total annual energy savings equivalent to approximately 166,000 MWH in 2009, 290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in 2012 and 530,000 MWH in 2013, with additional savings required through 2025. Utilities were also required to reduce peak demand in 2009 by 1%, with an additional 0.75% reduction each year thereafter through 2018.
In December 2009, the Ohio Companies filed the required three year portfolio plan seeking approval for the programs they intend to implement to meet the energy efficiency and peak demand reduction requirements for the 2010-2012 period. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers. The PUCO issued an Opinion and Order generally approving the Ohio Companies’ 3-year plan, and the Companies are in the process of implementing those programs included in the Plan. OE fell short of its statutory 2010 energy efficiency and peak demand reduction benchmarks and therefore, on January 11, 2011, it requested that its 2010 energy efficiency and peak demand reduction benchmarks be amended to actual levels achieved in 2010. The PUCO granted this request on May 19, 2011 for OE, finding that the motion was moot for CEI and TE. Moreover, because the PUCO indicated, when approving the 2009 benchmark request, that it would complement those currently being offered. The project relatingmodify the Companies’ 2010 (and 2011 and 2012) energy efficiency benchmarks when addressing the portfolio plan, the Ohio Companies were not certain of their 2010 energy efficiency obligations. Therefore, CEI and TE (each of which achieved its 2010 energy efficiency and peak demand reduction statutory benchmarks) also requested an amendment if and only to expansionthe degree one was deemed necessary to bring them into compliance with their yet-to-be-defined modified benchmarks. On June 2, 2011, the Companies filed an application for rehearing to clarify the decision related to CEI and TE. Failure to comply with the benchmarks or to obtain such an amendment may subject the companies to an assessment by the PUCO of a penalty. In addition to approving the programs included in the plan, with only minor modifications, the PUCO authorized the Companies to recover all costs related to the original CFL program that the Ohio Companies had previously suspended at the request of the PUCO. Applications for Rehearing were filed on April 22, 2011, regarding portions of the PUCO’s decision, including the method for calculating savings and certain changes made by the PUCO to specific programs. On May 4, 2011, the PUCO granted applications for rehearing for the purpose of further consideration; however, no substantive ruling has been issued.
Additionally under SB221, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they served in 2009 and 0.50% of the KWH they served in 2010. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RECs acquired through these two RFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. In March 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market and reduced the Ohio Companies’ aggregate 2009 benchmark to the level of solar RECs the Ohio Companies acquired through their 2009 RFP processes, provided the Ohio Companies’ 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC benchmark. FES also applied for a force majeure determination from the PUCO regarding a portion of their compliance with the 2009 solar energy resource benchmark. On February 23, 2011, the PUCO granted FES’ force majeure request for 2009 and increased its 2010 benchmark by the amount of SRECs that FES was short of in its 2009 benchmark. On April 15, 2011, the Ohio Companies filed an application seeking an amendment to each of their 2010 alternative energy requirements for solar RECs generated in Ohio on the basis that an insufficient quantity of solar resources are available in the market but reflecting solar RECs that they have obtained and providing additional information regarding efforts to secure solar RECs. Other parties to the proceeding filed comments asserting that the force majeure determination should not be granted, and others requesting the PUCO to review the costs the Ohio companies’ have incurred to comply with the renewable energy requirements. The PUCO has not yet acted on that application.
In February 2010, OE and CEI filed an application with the PUCO to establish a new credit for all-electric customers. In March 2010, the PUCO ordered that rates for the affected customers be set at a level that will provide bill impacts commensurate with charges in place on December 31, 2008 and authorized the Ohio Companies to defer incurred costs equivalent to the difference between what the affected customers would have paid under previously existing demand response programsrates and what they pay with the new credit in place. Tariffs implementing this new credit went into effect in March 2010. In April 2010, the PUCO issued a Second Entry on Rehearing that expanded the group of customers to which the new credit would apply and authorized deferral for the associated additional amounts. The PUCO also stated that it expected that the new credit would remain in place through at least the 2011 winter season and charged its staff to work with parties to seek a long term solution to the issue. Tariffs implementing this newly expanded credit went into effect in May 2010 and the proceeding remains open. The hearing on the matter was held in February 2011. The PUCO modified and approved the companies’ application on May 25, 2011, ruling that the new credit be phased out over an eight-year period and granting authority for the companies to recover deferred costs and associated carrying charges. OCC filed applications for rehearing on June 24, 2011 and the Ohio Companies filed their responses on July 5, 2011. The PUCO has not yet acted on the applications for rehearing.

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Pennsylvania
The PPUC entered an Order on March 3, 2010 that denied the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, directed Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructed Met-Ed and Penelec to work with the various intervening parties to file a recommendation to the PPUC regarding the establishment of a separate account for all marginal transmission losses collected from ratepayers plus interest to be used to mitigate future generation rate increases beginning January 1, 2011. In March 2010, Met-Ed and Penelec filed a Petition with the PPUC requesting that it stay the portion of the March 3, 2010 Order requiring the filing of tariff supplements to end collection of costs for marginal transmission losses. The PPUC granted the requested stay until December 31, 2010. Pursuant to the PPUC’s order, Met-Ed and Penelec filed plans to establish separate accounts for marginal transmission loss revenues and related interest and carrying charges. Pursuant to the plan approved by the NJBPU on August 19,PPUC, Met-Ed and Penelec began to refund those amounts to customers in January 2011, and the refunds will continue over a 29 month period until the full amounts previously recovered for marginal transmission loses are refunded. In April 2010, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania appealing the PPUC’s March 3, 2010 Order. On June 14, 2011, the Commonwealth Court issued an opinion and order affirming the PPUC’s Order to the extent that it holds that line loss costs are not transmission costs and, therefore, the approximately $254 million in marginal transmission losses and associated carrying charges for the period prior to January 1, 2011, are not recoverable under Met-Ed’s and Penelec’s TSC riders. Met-Ed and Penelec filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court and also a complaint seeking relief in federal district court. Although the ultimate outcome of this matter cannot be determined at this time, Met-Ed and Penelec believe that they should ultimately prevail through the judicial process and therefore expect to fully recover the approximately $254 million ($189 million for Met-Ed and $65 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011.
In May 2008, May 2009 and implementation began in 2009. ApprovalMay 2010, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider for the projectannual periods between June 1, 2008 to December 31, 2010, including marginal transmission losses as approved by the PPUC, although the recovery of marginal losses will be subject to the outcome of the proceeding related to the 2008 TSC filing as described above. The PPUC’s approval in May 2010 authorized an increase to the TSC for Met-Ed’s customers to provide for full recovery by December 31, 2010.
In February 2010, Penn filed a Petition for Approval of its Default Service Plan for the period June 1, 2011 through May 31, 2013. In July 2010, the parties to the proceeding filed a Joint Petition for Settlement of all issues. Although the PPUC’s Order approving the Joint Petition held that the provisions relating to the recovery of MISO exit fees and one-time PJM integration costs (resulting from Penn’s June 1, 2011 exit from MISO and integration into PJM) were approved, it made such provisions subject to the approval of cost recovery by FERC. Therefore, Penn may not put these provisions into effect until FERC has approved the recovery and allocation of MISO exit fees and PJM integration costs.
Pennsylvania adopted Act 129 in 2008 to address issues such as: energy efficiency programs intendedand peak load reduction; generation procurement; time-of-use rates; smart meters; and alternative energy. Among other things, Act 129 required utilities to complement those currently being offeredfile with the PPUC an energy efficiency and peak load reduction plan, or EE&C Plan, by July 1, 2009, setting forth the utilities’ plans to reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of 4.5% by May 31, 2013. Act 129 also required utilities to file with the PPUC a Smart Meter Implementation Plan (SMIP).
The PPUC entered an Order in February 2010 giving final approval to all aspects of the EE&C Plans of Met-Ed, Penelec and Penn and the tariff rider with rates effective March 1, 2010. On February 18, 2011, the companies filed a petition to approve their First Amended EE&C Plans. On June 28, 2011, a hearing on the petition was deniedheld before an administrative law judge.
WP filed its original EE&C Plan in June 2009, which the PPUC approved, in large part, by Opinion and Order entered in October 2009. In November 2009, the Office of Consumer Advocate (OCA) filed an appeal with the Commonwealth Court of the PPUC’s October Order. The OCA contends that the PPUC’s Order failed to include WP’s costs for smart meter implementation in the EE&C Plan, and that inclusion of such costs would cause the EE&C Plan to exceed the statutory cap for EE&C expenditures. The OCA also contends that WP’s EE&C plan does not meet the Total Resource Cost Test. The appeal remains pending but has been stayed by the NJBPUCommonwealth Court pending possible settlement of WP’s SMIP. In September 2010, WP filed an amended EE&C Plan that is less reliant on smart meter deployment, which the PPUC approved in January 2011.
Met-Ed, Penelec and Penn jointly filed a SMIP with the PPUC in August 2009. This plan proposed a 24-month assessment period in which Met-Ed, Penelec and Penn will assess their needs, select the necessary technology, secure vendors, train personnel, install and test support equipment, and establish a cost effective and strategic deployment schedule, which currently is expected to be completed in fifteen years. Met-Ed, Penelec and Penn estimate assessment period costs of approximately $29.5 million, which the Met-Ed, Penelec and Penn, in their plan, proposed to recover through an automatic adjustment clause. The ALJ’s Initial Decision approved the SMIP as modified by the ALJ, including: ensuring that the smart meters to be deployed include the capabilities listed in the PPUC’s Implementation Order; denying the recovery of interest through the automatic adjustment clause; providing for the recovery of reasonable and prudent costs net of resulting savings from installation and use of smart meters; and requiring that administrative start-up costs be expensed and the costs incurred for research and development in the assessment period be capitalized. The PPUC entered its Order in June 2010, consistent with the Chairman’s Motion. Met-Ed, Penelec and Penn filed a Petition for Reconsideration of a single portion of the PPUC’s Order regarding the future ability to include smart meter costs in base rates, which the PPUC granted in part by deleting language from its original order that would have precluded Met-Ed, Penelec and Penn from seeking to include smart meter costs in base rates at a later time. The costs to implement the SMIP could be material. However, assuming these costs satisfy a just and reasonable standard, they are expected to be recovered in a rider (Smart Meter Technologies Charge Rider) which was approved when the PPUC approved the SMIP.

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In August 2009, WP filed its original SMIP, which provided for extensive deployment of smart meter infrastructure with replacement of all of WP’s approximately 725,000 meters by the end of 2014. In December 2009, WP filed a motion to reopen the evidentiary record to submit an alternative smart meter plan proposing, among other things, a less-rapid deployment of smart meters. In an Initial Decision dated April 29, 2010, an ALJ determined that WP’s alternative smart meter deployment plan, complied with the requirements of Act 129 and recommended approval of the alternative plan, including WP’s proposed cost recovery mechanism.
In light of the significant expenditures that would be associated with its smart meter deployment plans and related infrastructure upgrades, as well as its evaluation of recent PPUC decisions approving less-rapid deployment proposals by other utilities, WP re-evaluated its Act 129 compliance strategy, including both its plans with respect to smart meter deployment and certain smart meter dependent aspects of the EE&C Plan. In October 2010, WP and Pennsylvania’s OCA filed a Joint Petition for Settlement addressing WP’s smart meter implementation plan with the PPUC. Under the terms of the proposed settlement, WP proposed to decelerate its previously contemplated smart meter deployment schedule and to target the installation of approximately 25,000 smart meters in support of its EE&C Plan, based on customer requests, by mid-2012. The proposed settlement also contemplates that WP take advantage of the 30-month grace period authorized by the PPUC to continue WP’s efforts to re-evaluate full-scale smart meter deployment plans. WP currently anticipates filing its plan for full-scale deployment of smart meters in June 2012. Under the terms of the proposed settlement, WP would be permitted to recover certain previously incurred and anticipated smart-meter related expenditures through a levelized customer surcharge, with certain expenditures amortized over a ten-year period. Additionally, WP would be permitted to seek recovery of certain other costs as part of its revised SMIP that it currently intends to file in June 2012, or in a future base distribution rate case.
In December 2010, the PPUC directed that the SMIP proceeding be referred to the ALJ for further proceedings to ensure that the impact of the proposed merger with FirstEnergy is considered and that the Joint Petition for Settlement has adequate support in the record. On March 9, 2011, WP submitted an Amended Joint Petition for Settlement which restates the Joint Petition for Settlement filed in October 2010, adds the PPUC’s Office of Trial Staff as a signatory party, and confirms the support or non-opposition of all parties to the settlement. One party retained the ability to challenge the recovery of amounts spent on WP’s original smart meter implementation plan. The proposed settlement also obligates OCA to withdraw its November 2009 appeal of the PPUC’s Order in WP’s EE&C plan proceeding. A Joint Stipulation with the OSBA was also filed on March 9, 2011. On May 3, 2011, the ALJ issued an Initial Decision recommending that the PPUC approve the Amended Joint Petition for Full Settlement. The PPUC approved the Initial Decision by order entered June 30, 2011.
By Tentative Order entered in September 2009, the PPUC provided for an additional 30-day comment period on whether the 1998 Restructuring Settlement, which addressed how Met-Ed and Penelec were going to implement direct access to a competitive market for the generation of electricity, allows Met-Ed and Penelec to apply over-collection of NUG costs for select and isolated months to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists. In response to the Tentative Order, various parties filed comments objecting to the above accounting method utilized by Met-Ed and Penelec. Met-Ed and Penelec are awaiting further action by the PPUC.
In the PPUC Order approving the FirstEnergy and Allegheny merger, the PPUC announced that a separate statewide investigation into Pennsylvania’s retail electricity market will be conducted with the goal of making recommendations for improvements to ensure that a properly functioning and workable competitive retail electricity market exists in the state. On April 29, 2011, the PPUC entered an Order initiating the investigation and requesting comments from interested parties on eleven directed questions. Met-Ed, Penelec, Penn Power and West Penn submitted joint comments on June 3, 2011. FES also submitted comments on June 3, 2011. On June 8, 2011, the PPUC conducted an en banc hearing on these issues at which both the Pennsylvania Companies and FES participated and offered testimony.
Virginia
In September 2010, PATH-VA filed an application with the VSCC for authorization to construct the Virginia portions of the PATH Project. On February 28, 2011, PATH-VA filed a motion to withdraw the application. On May 24, 2011, the VSCC granted PATH-VA’s motion to withdraw its application for authorization to construct the Virginia portions of the PATH Project. See “Transmission Expansion” in the Federal Regulation and Rate Matters section for further discussion of this matter.

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West Virginia
In August 2009, MP and PE filed with the WVPSC a request to increase retail rates, which was amended through subsequent filings. MP and PE ultimately requested an annual increase in retail rates of approximately $95 million. In April 2010, MP and PE filed with the WVPSC a Joint Stipulation and Agreement of Settlement reached with the other parties in the proceeding that provided for:
a $40 million annualized base rate increase effective June 29, 2010;
a deferral of February 2010 storm restoration expenses in West Virginia over a maximum five-year period;
•an additional $20 million annualized base rate increase effective in January 2011;
•a decrease of $20 million in ENEC rates effective January 2011, which amount is deferred for later recovery in 2012; and
a moratorium on filing for further increases in base rates before December 1, 2009. On July 6,2011, except under specified circumstances.
The WVPSC approved the Joint Petition and Agreement of Settlement in June 2010.
In 2009, the West Virginia Legislature enacted the Alternative and Renewable Energy Portfolio Act (Portfolio Act), which generally requires that a specified minimum percentage of electricity sold to retail customers in West Virginia by electric utilities each year be derived from alternative and renewable energy resources according to a predetermined schedule of increasing percentage targets, including ten percent by 2015, fifteen percent by 2020, and twenty-five percent by 2025. In November 2010, the WVPSC issued Rules Governing Alternative and Renewable Energy Portfolio Standard (RPS Rules), which became effective on January 30, 20094, 2011. Under the RPS Rules, on or before January 1, 2011, each electric utility subject to the provisions of this rule was required to prepare an alternative and renewable energy portfolio standard compliance plan and file an application with the WVPSC seeking approval of such plan. MP and PE filed their combined compliance plan in December 2010. A hearing was held at the WVPSC on June 13, 2011. An order is expected by late September 2011.
Additionally, in January 2011, MP and PE filed an application with the WVPSC seeking to certify three facilities as Qualified Energy Resource Facilities. If the application is approved, the three facilities would then be capable of generating renewable credits which would assist the companies in meeting their combined requirements under the Portfolio Act. Further, in February 2011, MP and PE filed a petition directedwith the WVPSC seeking an Order declaring that MP is entitled 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 costsall alternative and renewable energy resource credits associated with the proposal.electric energy, or energy and capacity, that MP is required to purchase pursuant to electric energy purchase agreements between MP and three non-utility electric generating facilities in WV. The City of New Martinsville and Morgantown Energy Associates, each the owner of one of the contracted resources, has participated in the case in opposition to the Petition.
FERC Matters
Rates for Transmission Service Between MISO and PJM
In November 2004, FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as SECA) during a 16-month transition period. In 2005, FERC set the SECA for hearing. The presiding ALJ issued an initial decision in August 2006, rejecting the compliance filings made by MISO, PJM and the transmission owners, and directing new compliance filings. This decision was subject to review and approval by FERC. In May 2010, FERC issued an order denying pending rehearing requests and an Order on Initial Decision which reversed the presiding ALJ’s rulings in many respects. Most notably, these orders affirmed the right of transmission owners to collect SECA charges with adjustments that modestly reduce the level of such charges, and changes to the entities deemed responsible for payment of the SECA charges. The Ohio Companies were identified as load serving entities responsible for payment of additional SECA charges for a portion of the SECA period (Green Mountain/Quest issue). FirstEnergy executed settlements with AEP, Dayton and the Exelon parties to fix FirstEnergy’s liability for SECA charges originally billed to Green Mountain and Quest for load that returned to regulated service during the SECA period. The AEP, Dayton and Exelon, settlements were approved by FERC in November 2010, and the relevant payments made. The subsidiaries of Allegheny entered into nine settlements to fix their liability for SECA charges with various parties. All of the settlements were approved by FERC and the relevant payments have been made for eight of the settlements. Payments due under the remaining settlement will be made as a part of the refund obligations of the Utilities that are under review by FERC as part of a compliance filing. Potential refund obligations of FirstEnergy and the Allegheny subsidiaries are not expected to be material. Rehearings remain pending in this proceeding.
PJM Transmission Rate
OnIn April 19, 2007, FERC issued an order (Opinion 494) finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate based on the amount of load served in a transmission zone. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a load flow methodology (DFAX), which is generally referred to as a “beneficiary pays” approach to allocating the cost of high voltage transmission facilities.

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The
FERC’s Opinion 494 order was appealed to the U.S. Court of Appeals for the Seventh Circuit, which issued a decision onin August 6, 2009. The court affirmed FERC’s ratemaking treatment for existing transmission facilities, but found that FERC had not supported its decision to allocate costs for new 500+ kV facilities on a load ratio share basis and, based on this finding, remanded the rate design issue back to FERC.
In an order dated January 21, 2010, FERC set the matter for a “paper hearings”hearing”—meaning that FERC called for parties to submit comments or written testimonycomments pursuant to the schedule described in the order. FERC identified nine separate issues for comments and directed PJM to file the first round of comments on February 22, 2010, with other parties submitting responsive comments and thethen reply comments.comments on later dates. PJM filed certain studies with FERC on April 13, 2010, in response to the FERC order. PJM’s filing demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain eastern utilities in PJM bearing the majority of theirthe costs. Numerous parties filed responsive comments or studies on May 28, 2010 and reply comments on June 28, 2010. FirstEnergy and a number of other utilities, industrial customers and state commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. Certain eastern utilities and their state commissions supported continued socialization of these costs on a load ratio share basis. This matter is awaiting action by FERC.
RTO Realignment
On June 1, 2011, ATSI and the ATSI zone entered into PJM. The move was performed as planned with no known operational or reliability issues for ATSI or for the wholesale transmission customers in the ATSI zone.
On February 1, 2011, ATSI in conjunction with PJM filed its proposal with FERC is expected to act beforefor moving its transmission rate into PJM’s tariffs. On April 1, 2011, the endMISO Transmission Owners (including ATSI) filed proposed tariff language that describes the mechanics of collecting and administering MTEP costs from ATSI-zone ratepayers. From March 20, 2011 through April 1, 2011, FirstEnergy, PJM and the MISO submitted numerous filings for the purpose of effecting movement of the year.

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RTO Consolidation
On December 17, 2009, FERC issued an order approving, subjectATSI zone to certain future compliance filings, ATSI’s move to PJM. This move, which is expected to be effectivePJM on June 1, 2011, allows FirstEnergy2011. These filings include amendments to consolidate its transmission assetsthe MISO’s tariffs (to remove the ATSI zone), submission of load and operationsgeneration interconnection agreements to reflect the move into PJM. Currently, FirstEnergy’s transmission assets and operations are divided between PJM, and MISO. The consolidation will make the transmission assets that are partsubmission of ATSI, whose footprint includes the Ohio Companies and Penn, part of PJM. In the order, FERC approved FirstEnergy’s proposalchanges to use a Fixed Resource Requirement Plan (FRR Plan)PJM’s tariffs to obtain capacity to satisfy the PJM capacity requirements for the 2011-12 and 2012-13 delivery years.
On December 17, 2009, ATSI executed the PJM Consolidated Transmission Owners Agreement and on December 18, 2009, the Ohio Companies and Penn executed the PJM Operating Agreement and the PJM Reliability Assurance Agreement. Execution of these agreements committed ATSI, the Ohio Companies and Penn tosupport the move into PJM.
FirstEnergy successfully conductedOn May 31, 2011, FERC issued orders that address the FRR auctions on March 19, 2010. Moreover,proposed ATSI transmission rate, and certain parts of the ATSI-zone loads participated inMISO tariffs that reflect the mechanics of transmission cost allocation and collection. In its May 31, 2011 orders, FERC approved ATSI’s proposal to move the ATSI formula rate into the PJM base residual auctiontariff without significant change. Speaking to ATSI’s proposed treatment of the MISO’s exit fees and charges for the 2013 delivery year. Successful completion of these steps secured the capacity necessary fortransmission costs that were allocated to the ATSI footprintzone, FERC required ATSI to meet PJM’s capacity requirements.
present a cost-benefit study that demonstrates that the benefits of the move for transmission customers exceed the costs of any such move, which FERC had not previously required. Accordingly, FERC ruled that these costs must be removed from ATSI’s proposed transmission rates until such time as ATSI files and FERC approves the cost-benefit study. On September 4, 2009,June 30, 2011, ATSI submitted the PUCO opened a case to take comments from Ohio’s stakeholders regardingcompliance filing that removed the RTO consolidation. On August 25, 2010, the PUCO issued an order that, among other things, committed the PUCO to close this case and also to withdraw its objections that were filed in the relevant FERC dockets conditioned upon the Ohio Companies not seeking recovery of MISO exit fees orand transmission cost allocation charges from ATSI’s proposed transmission rates. Also on June 30, 2011, ATSI requested rehearing of FERC’s decision to require a cost-benefit study analysis as part of FERC’s evaluation of ATSI’s proposed transmission rates. The compliance filing, and ATSI’s request for rehearing, are currently pending before FERC.
From late April 2011 through June 2011, FERC issued other orders that address ATSI’s move into PJM. These orders approve ATSI’s proposed interconnection agreements for large wholesale transmission customers and generators, and revisions to the PJM integrationand MISO tariffs that reflect ATSI’s move into PJM. In addition, FERC approved an “Exit Fee Agreement” that memorializes the agreement between ATSI and MISO with regard to ATSI’s obligation to pay certain administrative charges to the MISO upon exit. Finally, ATSI and the MISO were able to negotiate an agreement of ATSI’s responsibility for certain charges associated with long term firm transmission rights — that, according to the MISO, were payable by the ATSI zone upon its departure from the MISO. ATSI did not and does not agree that these costs (estimatedshould be charged to be approximately $37ATSI but, in order to settle the case and all claims associated with the case, ATSI agreed to a one-time payment of $1.8 million asto the MISO. This settlement agreement has been submitted for FERC’s review and approval. The final outcome of September 30, 2010). Notwithstandingthose proceedings that address the PUCO’s actions, certain other parties protested aspects of theremaining open issues related to ATSI’s move into PJM and certain of these matters remain outstanding and willtheir impact, if any, on FirstEnergy cannot be resolved in future FERC proceedings. Under the terms of the ESP order issued August 25, 2010, the PUCO has agreed to closepredicted at this docket.time.
MISO Multi-Value Project Rule Proposal
OnIn July 15, 2010, MISO and certain MISO transmission owners jointly filed with FERC their proposed cost allocation methodology for certain new transmission projects. The new transmission projects—described as Multi-Value Projects (MVPs)MVPs —are a class of MTEP projects.transmission projects that are approved via MISO’s formal transmission planning process (the MTEP). The MISO proposesfiling parties proposed to allocate the costs of MVPs by means of a usage-based charge that will be applied to all loads within the MISO footprint, and to energy transactions that call for power to be “wheeled through” the MISO as well as to energy transactions that “source” in the MISO but “sink” outside of MISO. MISO expectsThe filing parties expect that itsthe MVP proposal will fund the costs of large transmission projects designed to bring wind generation from the upper Midwest to load centers in the east. MISO hasThe filing parties requested that FERC rule on its MVP proposal by December, but has asked for an effective date for itsthe proposal of July 16, 2011. On August 19, 2010, MISO’s Board approved the first MVP project—project — the so-called “Michigan Thumb Project.” Under MISO’s proposal, the costs of MVP projects approved by MISO’s Board prior to the anticipated June 1, 2011 effective date of FirstEnergy’s integration into PJM would continue to be allocated to FirstEnergy. This approach is reflected in the MISO’sMISO estimated allocations of the costs for the Michigan Thumb Project, wherethat approximately $16$15 million in annual revenue requirements werewould be allocated to the ATSI zone.zone associated with the Michigan Thumb Project upon its completion.

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On
In September 10, 2010, FirstEnergy filed a protest to MISO’sthe MVP proposal. FirstEnergy believesproposal arguing that MISO’s proposal to allocate costs of MVPMVPs projects across the entire MISO footprint does not align with the established rule that cost allocation is to be based on cost causation (the “beneficiary pays” approach). FirstEnergy also argued that, in light of progress that had been made to date in the ATSI move tointegration into PJM, it would be unjust and unreasonable to allocate any MVP costs to the ATSI zone, or to ATSI. Numerous other parties filed pleadings on MISO’s MVP proposal.
In December 2010, FERC issued an order approving the MVP proposal without significant change. FERC’s order was not clear, however, as to whether the MVP costs would be payable by ATSI or load in the ATSI zone. FERC stated that the MISO’s tariffs obligate ATSI to pay all charges that attached prior to ATSI’s exit but ruled that the question of the amount of costs that are to be allocated to ATSI or to load in the ATSI zone were beyond the scope of FERC’s order and would be addressed in future proceedings.
On January 18, 2011, FirstEnergy filed for rehearing of FERC’s order. In its rehearing request, FirstEnergy argued that because the MVP rate is unableusage-based, costs could not be applied to ATSI, which is a stand-alone transmission company that does not use the transmission system. FirstEnergy also renewed its arguments regarding cost causation and the impropriety of allocating costs to the ATSI zone or to ATSI.
As noted above, on February 1, 2011, ATSI filed proposed transmission rates related to its move into PJM. The proposed rates included line items that were intended to recover all MVP costs (if any) that might be charged to ATSI or to the ATSI zone. In its May 31, 2011 order on ATSI’s proposed transmission rates FERC ruled that ATSI must submit a cost-benefit study before ATSI can recover the MVP costs. FERC further directed that ATSI remove the line-items from ATSI’s formula rate that would recover the MVP costs until such time as ATSI submits and FERC approves the cost-benefit study. ATSI requested a rehearing of these parts of FERC’s order and, pending this further legal process, has removed the MVP line items from its transmission rates.
FirstEnergy cannot predict the outcome of these proceedings at this time.
California Claims Matters
In October 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the California Department of Water Resources (CDWR) during 2001. The settlement proposal claims that CDWR is owed approximately $190 million for these alleged overcharges. This proposal was made in the context of mediation efforts by FERC and the United States Court of Appeals for the Ninth Circuit in pending proceedings to resolve all outstanding refund and other claims, including claims of alleged price manipulation in the California energy markets during 2000 and 2001. The Ninth Circuit has since remanded one of those proceedings to FERC, which arises out of claims previously filed with FERC by the California Attorney General on behalf of certain California parties against various sellers in the California wholesale power market, including AE Supply (the Lockyer case). AE Supply and several other sellers filed motions to dismiss the Lockyer case. In March 2010, the judge assigned to the case entered an opinion that granted the motions to dismiss filed by AE Supply and other sellers and dismissed the claims of the California Parties. On May 4, 2011, FERC affirmed the judge’s ruling.
In June 2009, the California Attorney General, on behalf of certain California parties, filed a second complaint with FERC against various sellers, including AE Supply (the Brown case), again seeking refunds for trades in the California energy markets during 2000 and 2001. The above-noted trades with CDWR are the basis for including AE Supply in this new complaint. AE Supply filed a motion to dismiss the Brown complaint that was granted by FERC on May 24, 2011. On June 23, 2011, the California Attorney General requested rehearing of the May 24, 2011 order. FirstEnergy cannot predict the outcome of this matter.
Transmission Expansion
TrAIL Project.TrAIL is a 500 kV transmission line extending from southwest Pennsylvania through West Virginia and into northern Virginia. Effective May 19, 2011, all segments of TrAIL were energized and in service.
PATH Project.The PATH Project is comprised of a 765 kV transmission line that was proposed to extend from West Virginia through Virginia and into Maryland, modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland.

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PJM initially authorized construction of the PATH Project in June 2007. In December 2010, PJM advised that its 2011 Load Forecast Report included load projections that are different from previous forecasts and that may have an impact on the proposed in-service date for the PATH Project. As part of its 2011 RTEP, and in response to a January 19, 2011 directive by a Virginia Hearing Examiner, PJM conducted a series of analyses using the most current economic forecasts and demand response commitments, as well as potential new generation resources. Preliminary analysis revealed the expected reliability violations that necessitated the PATH Project had moved several years into the future. Based on those results, PJM announced on February 28, 2011 that its Board of Managers had decided to hold the PATH Project in abeyance in its 2011 RTEP and directed FirstEnergy and AEP, as the sponsoring transmission owners, to suspend current development efforts on the project, subject to those activities necessary to maintain the project in its current state, while PJM conducts more rigorous analysis of the need for the project as part of its continuing RTEP process. PJM stated that its action did not constitute a directive to FirstEnergy and AEP to cancel or abandon the PATH Project. PJM further stated that it will complete a more rigorous analysis of the PATH Project and other transmission requirements and its Board will review this comprehensive analysis as part of its consideration of the 2011 RTEP. On February 28, 2011, affiliates of FirstEnergy and AEP filed motions or notices to withdraw applications for authorization to construct the project that were pending before state commissions in West Virginia, Virginia and Maryland. Withdrawal was deemed effective upon filing the notice with the MDPSC. The WVPSC and VSCC have granted the motions to withdraw.
PATH, LLC submitted a filing to FERC to implement a formula rate tariff effective March 1, 2008. In a November 19, 2010 order addressing various matters relating to the formula rate, FERC set the project’s base return on equity for hearing and reaffirmed its prior authorization of a return on CWIP, recovery of start-up costs and recovery of abandonment costs. In the order, FERC also granted a 1.5% return on equity incentive adder and a 0.50% return on equity adder for RTO participation. These adders will be applied to the base return on equity determined as a result of the hearing. PATH, LLC is currently engaged in settlement discussions with the staff of FERC and intervenors regarding resolution of the base return on equity.
Seneca Pumped Storage Project Relicensing
The Seneca (Kinzua) Pumped Storage Project is a 451 MW hydroelectric project located in Warren County, Pennsylvania owned and operated by FGCO. FGCO holds the current FERC license that authorizes ownership and operation of the project. The current FERC license will expire on November 30, 2015. FERC’s regulations call for a five-year relicensing process. On November 24, 2010, and acting pursuant to applicable FERC regulations and rules, FGCO initiated the relicensing process by filing its notice of intent to relicense and pre-application document (PAD) in the license docket.
On November 30, 2010, the Seneca Nation of Indians filed its notice of intent to relicense and PAD documents necessary for them to submit a competing application. Section 15 of the FPA contemplates that third parties may file a ‘competing application’ to assume ownership and operation of a hydroelectric facility upon (i) relicensure and (ii) payment of net book value of the plant to the original owner/operator. Nonetheless, FGCO believes it is entitled to a statutory “incumbent preference” under Section 15.
The Seneca Nation and certain other intervenors have asked FERC to redefine the “project boundary” of the hydroelectric plant to include the dam and reservoir facilities operated by the U.S. Army Corps. of Engineers. On May 16, 2011, FirstEnergy filed a Petition for Declaratory Order with FERC seeking an order to exclude the dam and reservoir facilities from the project. The Seneca Nation, the New York State Department of Environmental Conservation, and the U.S. Department of Interior each submitted responses to FirstEnergy’s petition, including motions to dismiss FirstEnergy’s petition. The “project boundary” issue is pending before FERC.
The next steps in the relicensing process are for FirstEnergy and the Seneca Nation to define and perform certain environmental and operational studies to support their respective applications. These steps are expected to run through approximately November of 2013. FirstEnergy cannot predict the outcome of these proceedings at this time.
Environmental Matters
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. Compliance with environmental regulations could have a material adverse effect on FirstEnergy’s earnings and competitive position to the extent that FirstEnergy competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations.
CAA Compliance
FirstEnergy is required to meet federally-approved SO2SO2 and NOXNOx emissions regulations under the CAA. FirstEnergy complies with SO2 and NOx reduction requirements under the CAA and SIP(s) under the CAA by burning lower-sulfur fuel, combustion controls and post-combustion controls, generating more electricity from lower-emitting plants and/or using emission allowances. Violations can result in the shutdown of the generating unit involved and/or civil or criminal penalties.

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The Sammis, Burger, Eastlake and Mansfield coal-fired plants are operated under a consent decree with the EPA and DOJ that requires reductions of 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, PennFutureJuly 2008, three complaints were filed a citizen suit under the CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations,against FGCO in the U.S. District Court for the Western District of Pennsylvania. In July 2008, three additional complaints were filed against FGCOPennsylvania seeking damages based on coal-fired 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”,manner,” one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint seeking certification as a class action with the eight named plaintiffs as the class representatives. A settlement was reached with PennFuture. FGCO believes the claims of the remaining plaintiffs are without merit and intends to defend itself against the allegations made in thosethese three complaints.

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The states of New Jersey and Connecticut filed CAA citizen suits in 2007 alleging NSR violations at the Portland Generation Station against GenOn Energy, Inc. (formerly RRI Energy, Inc. (theand the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999) and Met-Ed. Specifically, these suits allege that “modifications” at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR permitting in violation of the CAA’s PSD program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. In September 2009, the Court granted Met-Ed’s motion to dismiss New Jersey’s and Connecticut’s claims for injunctive relief against Met-Ed, but denied Met-Ed’s motion to dismiss the claims for civil penalties. The parties dispute the scope of Met-Ed’s indemnity obligation to and from Sithe Energy.Energy, and Met-Ed is unable to predict the outcome of this matter.
In January 2009, the EPA issued a NOV to ReliantGenOn Energy, Inc. alleging NSR violations at the Portland Generation Stationcoal-fired plant based on “modifications” dating back to 19861986. On March 31, 2011, the EPA proposed emissions limits and compliance schedules to reduce SO2 air emissions by approximately 81% at the Portland Plant based on an interstate pollution transport petition submitted by New Jersey under Section 126 of the CAA. The NOV also alleged NSR violations at the Keystone and Shawville Stationscoal-fired plants based on “modifications” dating back to 1984. Met-Ed, JCP&L, as the former owner of 16.67% of the Keystone, Station, and Penelec, as former owner and operator of the Shawville, Station, are unable to predict the outcome of this matter.
In June 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. (Mission) alleging that “modifications” at the coal-fired Homer City Power StationPlant occurred sincefrom 1988 to the present without preconstruction NSR permitting in violation of the CAA’s PSD program. In May 2010, the EPA issued a second NOV to Mission, Energy Westside, Inc., Penelec, New York State Electric & Gas Corporation and others that have had an ownership interest in the Homer City Power Station containing in all material respects allegations identical allegations asto those included in the June 2008 NOV. On July 20, 2010,In January 2011, the statesDOJ filed a complaint against Penelec in the U.S. District Court for the Western District of Pennsylvania seeking injunctive relief against Penelec based on alleged “modifications” at Homer City between 1991 to 1994 without preconstruction NSR permitting in violation of the CAA’s PSD and Title V permitting programs. The complaint was also filed against the former co-owner, New York State Electric and Gas Corporation, and various current owners of Homer City, including EME Homer City Generation L.P. and affiliated companies, including Edison International. In January 2011, another complaint was filed against Penelec and the other entities described above in the U.S. District Court for the Western District of Pennsylvania seeking damages based on Homer City’s air emissions as well as certification as a class action and to enjoin Homer City from operating except in a “safe, responsible, prudent and proper manner.” Penelec believes the claims are without merit and intends to defend itself against the allegations made in the complaint, but, at this time, is unable to predict the outcome of this matter. In addition, the Commonwealth of Pennsylvania and the States of New Jersey and New York intervened and Pennsylvania provided Mission Energy Westside, Inc., Penelec, NYSEG and others that have had an ownership interest in thefiled separate complaints regarding Homer City Power Station a notification required 60 days prior to filing a citizen suit under the CAA.seeking injunctive relief and civil penalties. Mission Energy Westside, Inc. is seeking indemnification from Penelec, the co-owner and operator of the Homer City Power Station prior to its sale in 1999. On April 21, 2011, Penelec and all other defendants filed Motions to Dismiss all of the federal claims and the various state claims. Responsive and Reply briefs were filed on May 26, 2011 and June 17, 2011, respectively. 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 generatingcoal-fired plants. The EPA’s NOV alleges equipment replacements occurring during maintenance outages dating back to 1990 triggered the pre-construction permitting requirements under the PSD and NNSR programs. FGCO received a request for certain operating and maintenance information and planning information for these same generating plants and notification that the EPA is evaluating whether certain maintenance at the Eastlake generating plantPlant 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 Eastlake Plant. In June 2011, EPA issued another Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, specifically opacity limitations and requirements to continuously operate opacity monitoring systems at the Eastlake, generating plant.Lakeshore, Bay Shore and Ashtabula coal-fired plants. Also, in June 2011, FirstEnergy received an information request pursuant to section 114(a) of the CAA for certain operating maintenance and planning information, among other information regarding these plants. FGCO intends to comply with the CAA, including the EPA’s information requests but, at this time, is unable to predict the outcome of this matter.
In August 2000, AE received an information request pursuant to section 114(a) of the CAA letter from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the following ten coal-fired plants, which collectively include 22 electric generation units Albright, Armstrong, Fort Martin, Harrison, Hatfield’s Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island to determine compliance with the CAA and related requirements, including potential application of the NSR standards under the CAA, which can require the installation of additional air emission control equipment when the major modification of an existing facility results in an increase in emissions. AE has provided responsive information to this and a subsequent request but is unable to predict the outcome of this matter.
In May 2004, AE, AE Supply, MP and WP received a Notice of Intent to Sue Pursuant to CAA §7604 from the Attorneys General of New York, New Jersey and Connecticut and from the PA DEP, alleging that Allegheny performed major modifications in violation of the PSD provisions of the CAA at the following West Virginia coal-fired plants: Albright Unit 3; Fort Martin Units 1 and 2; Harrison Units 1, 2 and 3; Pleasants Units 1 and 2 and Willow Island Unit 2. The Notice also alleged PSD violations at the Armstrong, Hatfield’s Ferry and Mitchell coal-fired plants in Pennsylvania and identifies PA DEP as the lead agency regarding those facilities. In September 2004, AE, AE Supply, MP and WP received a separate Notice of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.

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In June 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed suit against AE, AE Supply, MP, PE and WP in the United States District Court for the Western District of Pennsylvania alleging, among other things, that Allegheny performed major modifications in violation of the CAA and the Pennsylvania Air Pollution Control Act at the Hatfield’s Ferry, Armstrong and Mitchell Plants in Pennsylvania. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. A non-jury trial on liability only was held in September 2010. Plaintiffs filed their proposed findings of fact and conclusions of law in December 2010, Allegheny made its related filings in February 2011 and plaintiffs filed their responses in April 2011. The parties are awaiting a decision from the District Court, but there is no deadline for that decision.
In September 2007, Allegheny also received a NOV from the EPA alleging NSR and PSD violations under the CAA, as well as Pennsylvania and West Virginia state laws at the Hatfield’s Ferry and Armstrong Plants in Pennsylvania and the Fort Martin and Willow Island coal-fired plants in West Virginia.
FirstEnergy intends to vigorously defend against the CAA matters described above but cannot predict their outcomes.
State Air Quality Compliance
In early 2006, Maryland passed the Healthy Air Act, which imposes state-wide emission caps on SO2 and NOX, requires mercury emission reductions and mandates that Maryland join the RGGI and participate in that coalition’s regional efforts to reduce CO2 emissions. On April 20, 2007, Maryland became the 10th state to join the RGGI. The Healthy Air Act provides a conditional exemption for the R. Paul Smith coal-fired plant for NOX, SO2 and mercury, based on a PJM declaration that the plant is vital to reliability in the Baltimore/Washington DC metropolitan area, which PJM determined in 2006. Pursuant to the legislation, the Maryland Department of the Environment (MDE) passed alternate NOX and SO2 limits for R. Paul Smith, which became effective in April 2009. However, R. Paul Smith is still required to meet the Healthy Air Act mercury reductions of 80% beginning in 2010. The statutory exemption does not extend to R. Paul Smith’s CO2 emissions. Maryland issued final regulations to implement RGGI requirements in February 2008. Ten RGGI auctions have been held through the end of calendar year 2010. RGGI allowances are also readily available in the allowance markets, affording another mechanism by which to secure necessary allowances. On March 14, 2011, MDE requested PJM perform an analysis to determine if termination of operation at R. Paul Smith would adversely impact the reliability of electrical service in the PJM region under current system conditions. FirstEnergy is unable to predict the outcome of this matter.
In January 2010, the WVDEP issued a NOV for opacity emissions at Allegheny’s Pleasants coal-fired plant. FirstEnergy is discussing with WVDEP steps to resolve the NOV including installing a reagent injection system to reduce opacity.
National Ambient Air Quality Standards
The EPA’s CAIR requires reductions of NOXNOx and SO2 emissions in two phases (2009/2010 and 2015), ultimately capping SO2SO2 emissions in affected states to 2.5 million tons annually and NOXNOx emissions to 1.3 million tons annually. In 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” In December 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s opinion. The Court ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOX“NOx SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the “8-hour” ozone NAAQS. In July 2010,2011, the EPA proposedfinalized the CleanCross-State Air TransportPollution Rule (CATR)(CSAPR) to replace CAIR, which remains in effect until CSAPR becomes effective (60 days after publication in the EPA finalizes CATR. CATRFederal Register). CSAPR requires reductions of NOXNOx and SO2SO2 emissions in two phases (2012 and 2014), ultimately capping SO2SO2 emissions in affected states to 2.62.4 million tons annually and NOXNOx emissions to 1.31.2 million tons annually. The EPA proposed a preferred regulatory approach thatCSAPR allows trading of NOXNOx and SO2 emission allowances between power plants located in the same state and severely limits interstate trading of NOx and SO2 emission allowances. The EPA also requested comment on two alternative approaches—the first eliminates interstate trading of NOX and SO2 emission allowances and the second eliminates trading of NOX and SO2 emission allowances in its entirety. Depending on the actions taken by the EPA with respect to CATR, the proposed MACT regulations discussed below and any future regulations that are ultimately implemented,some restrictions. FGCO’s future cost of compliance may be substantial.substantial and changes to FirstEnergy’s operations may result. Management is currently assessing the impact of theseCSAPR, other environmental proposals and other factors on FGCO’sFirstEnergy’s competitive fossil generating facilities, particularlyincluding but not limited to, the impact on value of our emissions allowances (currently reflected at $38 million on our Consolidated Balance Sheet as of June 30, 2011) and the operationoperations of its smaller, non-supercritical units. For example, as disclosed herein, management decided to idle certain units or operate them on a seasonal basis until developments clarify.coal-fired plants.

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Hazardous Air Pollutant Emissions
The EPA’s CAMR provides for a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping nationwide emissions of mercury at 38 tons by 2010 (as a “co-benefit” from implementation of SO2 and NOX emission caps under the EPA’s CAIR program) and 15 tons per year by 2018. The U.S. Court of Appeals for the District of Columbia, at the urging of several states and environmental groups, vacated the CAMR, ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. On April 29, 2010, the EPA issued proposed maximum achievable control technology (MACT) regulations requiring emissions reductions of mercury and other hazardous air pollutants from non-electric generating unit boilers, including boilers which do not use fossil fuels such as the proposed Burger biomass repowering project. On September 1, 2010, the EPA classified Burger as an existing source for purposes of the industrial Boiler MACT. If finalized, the non-electric generating unit MACT regulations could also provide precedent for MACT standards applicable to electric generating units. The EPA entered into a consent decree requiring it to propose MACT regulations for mercury and other hazardous air pollutants from electric generating units by March 16, 2011, the EPA released its MACT proposal to establish emission standards for mercury, hydrochloric acid and to finalize the regulations by November 16, 2011.various metals for electric generating units. Depending on the action taken by the EPA and on how any future regulations are ultimately implemented, FGCO’sFirstEnergy’s future cost of compliance with MACT regulations may be substantial and changes to FGCO’sFirstEnergy’s operations may result.

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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, onin June 26, 2009. The Senate continues to consider a number of measures to regulate GHG emissions. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuringproposals to ensure that 10% of electricity used in the United States comes from renewable sources by 2012, increasingto increase to 25% by 2025, and implementingto implement an economy-wide cap-and-trade program to reduce GHG emissions by 80% by 2050. State activities,Certain states, primarily the northeastern states participating in the Regional Greenhouse Gas InitiativeRGGI and western states, led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.
In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that will requirerequired FirstEnergy to measure GHG emissions commencing in 2010 and will require it to submit reports commencing in 2011. In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s finding concludes that concentrations of several key GHGs increase the threat of climate change and may be regulated as “air pollutants” under the CAA. In April 2010, the EPA finalized new GHG standards for model years 2012 to 2016 passenger cars, light-duty trucks and medium-duty passenger vehicles and clarified that GHG regulation under the CAA would not be triggered for electric generating plants and other stationary sources until January 2, 2011, at the earliest. In May 2010, the EPA finalized new thresholds for GHG emissions that define when permits under the CAA’s NSR program would be required. The EPA established an emissions applicability threshold of 75,000 tons per year (tpy) of carbon dioxide equivalents (CO2e)(CO2) effective January 2, 2011 for existing facilities under the CAA’s PSD program, but untilprogram. Until July 1, 2011, thatthis emissions applicability threshold will only apply if PSD is triggered by non-carbon dioxidenon-CO2 pollutants.
At the international level, the Kyoto Protocol, signed by the U.S. in 1998 but never submitted for ratification by the U.S. Senate, was intended to address global warming by reducing the amount of man-made GHG, including CO2, emitted by developed countries by 2012. A December 2009 U.N. Climate Change Conference in Copenhagen did not reach a consensus on a successor treaty to the Kyoto Protocol, but did take note of the Copenhagen Accord, a non-binding political agreement whichthat recognized the scientific view that the increase in global temperature should be below two degrees Celsius; includeincludes a commitment by developed countries to provide funds, approaching $30 billion over the next three years with a goal of increasing to $100 billion by 2020; and establishestablishes the “Copenhagen Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. OnceTo the extent that they have become a party to the Copenhagen Accord, developed economies, such as the European Union, Japan, Russia and the United States, would commit to quantified economy-wide emissions targets from 2020, while developing countries, including Brazil, China and India, would agree to take mitigation actions, subject to their domestic measurement, reporting and verification.

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On September 21,In 2009, the U.S. Court of Appeals for the Second Circuit and on October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit reversed and remanded lower court decisions that had dismissed complaints alleging damage from GHG emissions on jurisdictional grounds. However, a subsequent ruling from the U.S. Court of Appeals for the Fifth Circuit reinstated the lower court dismissal of a complaint alleging damage from GHG emissions. These cases involve common law tort claims, including public and private nuisance, alleging that GHG emissions contribute to global warming and result in property damages. The U.S. Supreme Court granted a writ of certiorari to review the decision of the Second Circuit. On June 20, 2011, the U. S. Supreme Court reversed the Second Circuit. The Court remanded to the Second Circuit the issue of whether the CAA preempted state common law nuisance actions. The Court’s ruling also failed to answer the question of the extent to which actions for damages may remain viable. While FirstEnergy is not a party to this litigation, in June 2011, FirstEnergy and/or one or morereceived notice of its subsidiaries could be named in actions making similar allegations.a complaint alleging that the GHG emissions of 87 companies, including FirstEnergy, render them liable for damages to certain residents of Mississippi stemming from Hurricane Katrina. On July 27, 2011, the plaintiff voluntarily dismissed FirstEnergy from this complaint.
FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO2 emissions per KWH of electricity generated by FirstEnergy is lower than many of its regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy’s plants. In addition, Ohio, New Jersey and Pennsylvaniathe states in which FirstEnergy operates have water quality standards applicable to FirstEnergy’s operations.
TheIn 2004, 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). TheIn 2007, the Court of Appeals for the Second Circuit invalidated portions of the Section 316(b) performance standards and the EPA has taken the position that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. OnIn April 1, 2009, the U.S. Supreme Court reversed one significant aspect of the Second Circuit’s opinion and decided that Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with

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benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. TheOn March 28, 2011, the EPA is developingreleased a new proposed regulation under Section 316(b) of the Clean Water Act consistent withgenerally requiring fish impingement to be reduced to a 12% annual average and studies to be conducted at the opinionsmajority of our existing generating facilities to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic life. On July 19, 2011, the Supreme Court andEPA extended the Court of Appeals which have created significant uncertainty aboutpublic comment period for the specific nature, scope and timing of thenew proposed Section 316(b) regulation by 30 days but stated its schedule for issuing a final performance standard.rule remains July 27, 2012. FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore power plant’s water intake channel to divert fish away from the plant’s water intake system. On March 15,In November 2010, the Ohio EPA issued a draft permit for the coal-fired Bay Shore power plantPlant requiring installation of reverse louvers in its entire water intake channel by December 31, 2014. Depending on the results of such studies and the EPA’s further rulemaking and any final action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.
In June 2008,April 2011, the U.S. Attorney’s Office in Cleveland, Ohio advised FGCO that it is no longer considering prosecution under the Clean Water Act and the Migratory Bird Treaty Act for three petroleum spills at the Edgewater, Lakeshore and Bay Shore plants which occurred on November 1, 2005, January 26, 2007 and February 27, 2007. This matter has been referred back to EPA for civil enforcement and FGCO is unable to predict the outcome of this matter.
In May 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club filed a CWA citizen suit alleging violations of arsenic limits in the NPDES water discharge permit for the fly ash disposal site at the Albright coal-fired plant seeking unspecified civil penalties and injunctive relief. MP is currently seeking relief from the arsenic limits through WVDEP agency review. In June 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club served another 60-Day Notice of Intent required prior to filing a citizen suit under the Clean Water Act for alleged failure to obtain a permit to construct the fly ash impoundments at the Albright Station.
FirstEnergy intends to vigorously defend against the CWA matters described above but cannot predict their outcomes.
Monongahela River Water Quality
In late 2008, the PA DEP imposed water quality criteria for certain effluents, including TDS and sulfate concentrations in the Monongahela River, on new and modified sources, including the scrubber project at the Hatfield’s Ferry coal-fired plant. These criteria are reflected in the current PA DEP water discharge permit for that project. AE Supply appealed the PA DEP’s permitting decision, which would require it to incur significant costs or negatively affect its ability to operate the scrubbers as designed. Preliminary studies indicate an initial capital investment in excess of $150 million in order to install technology to meet the TDS and sulfate limits in the permit. The permit has been independently appealed by Environmental Integrity Project and Citizens Coal Council, which seeks to impose more stringent technology-based effluent limitations. Those same parties have intervened in the appeal filed by AE Supply, and both appeals have been consolidated for discovery purposes. An order has been entered that stays the permit limits that AE Supply has challenged while the appeal is pending. The hearing is scheduled to begin in September 2011, however the Court stayed all prehearing deadlines on July 15, 2011 to allow the parties additional time to work out a settlement. AE Supply intends to vigorously pursue these issues, but cannot predict the outcome of these appeals.
In a parallel rulemaking, the PA DEP recommended, and in August 2010, the Pennsylvania Environmental Quality Board issued, a final rule imposing end-of-pipe TDS effluent limitations. FirstEnergy could incur significant costs for additional control equipment to meet the requirements of this rule, although its provisions do not apply to electric generating units until the end of 2018, and then only if the EPA has not promulgated TDS effluent limitation guidelines applicable to such units.
In December 2010, PA DEP submitted its Clean Water Act 303(d) list to the EPA with a recommended sulfate impairment designation for an approximately 68 mile stretch of the Monongahela River north of the West Virginia border. In May 2011, the EPA agreed with PA DEP’s recommended sulfate impairment designation. PA DEP’s goal is to submit a final water quality standards regulation, incorporating the sulfate impairment designation for EPA approval by May, 2013. PA DEP will then need to develop a TMDL limit for the river, a process that will take approximately five years. Based on the stringency of the TMDL, FirstEnergy may incur significant costs to reduce sulfate discharges into the Monongahela River from its Hatfield’s Ferry and Mitchell facilities in Pennsylvania and its Fort Martin facility in West Virginia.
In October 2009, the WVDEP issued the water discharge permit for the Fort Martin generation facility. Similar to the Hatfield’s Ferry water discharge permit issued for the scrubber project, the Fort Martin permit imposes effluent limitations for TDS and sulfate concentrations. The permit also imposes temperature limitations and other effluent limits for heavy metals that are not contained in the Hatfield’s Ferry water permit. Concurrent with the issuance of the Fort Martin permit, WVDEP also issued an administrative order that sets deadlines for MP to meet certain of the effluent limits that are effective immediately under the terms of the permit. MP appealed the Fort Martin permit and the administrative order. The appeal included a request to stay certain of the conditions of the permit and order while the appeal is pending, which was granted pending a final decision on appeal and subject to WVDEP moving to dissolve the stay. The appeals have been consolidated. MP moved to dismiss certain of the permit conditions for the failure of the WVDEP to submit those conditions for public review and comment during the permitting process. An agreed-upon order that suspends further action on this appeal, pending WVDEP’s release for public review and comment on those conditions, was entered on August 11, 2010. The stay remains in effect during that process. The current terms of the Fort Martin permit would require MP to incur significant costs or negatively affect operations at Fort Martin. Preliminary information indicates an initial capital investment in excess of the capital investment that may be needed at Hatfield’s Ferry in order to install technology to meet the TDS and sulfate limits in the Fort Martin permit, which technology may also meet certain of the other effluent limits in the permit. Additional technology may be needed to meet certain other limits in the permit. MP intends to vigorously pursue these issues but cannot predict the outcome of these appeals.

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Regulation of Waste Disposal
Federal and state hazardous waste regulations have been promulgated as a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976. Certain fossil-fuel combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation. In February 2009, the EPA requested comments from the states on options for regulating coal combustion residuals, including whether they should be regulated as hazardous or non-hazardous waste.
OnIn December 30, 2009, in an advanced notice of public rulemaking, the EPA saidasserted that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. OnIn May 4, 2010, the EPA proposed two options for additional regulation of coal combustion residuals, including the option of regulation as a special waste under the EPA’s hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. FGCO’sFirstEnergy’s future cost of compliance with any coal combustion residuals regulations whichthat may be promulgated could be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the EPA or the states.

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The UtilitiesLittle Blue Run (LBR) Coal Combustion By-products (CCB) impoundment is expected to run out of disposal capacity for disposal of CCBs from the Bruce Mansfield Plant between 2016 and 2018. In July 2011, BMP submitted a Phase I permit application to PA DEP for construction of a new dry CCB disposal facility adjacent to LBR. BMP anticipates submitting zoning applications for approval to allow construction of a new dry CCB disposal facility prior to commencing construction.
The Utility Registrants have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the consolidated balance sheet as of SeptemberJune 30, 2010,2011, based on estimates of the total costs of cleanup, the Utilities’Utility Registrants’ proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $105$133 million (JCP&L — $76$69 million, TE — $1 million, CEI — $1 million, FGCO — $1 million and FirstEnergy — $26$61 million) have been accrued through SeptemberJune 30, 2010.2011. Included in the total are accrued liabilities of approximately $67$63 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. On July 11, 2011, FirstEnergy was found to be a potentially responsible party under CERCLA indirectly liable for a portion of past and future clean-up costs at certain legacy MGP sites, estimated to total approximately $59 million. FirstEnergy recognized additional expense of $29 million during the second quarter of 2011; $30 million had previously been reserved prior to 2011.
Other Legal Proceedings
Power Outages and Related Litigation
In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L’s territory.&L. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages due to the outages. After various motions, rulings and appeals, the Plaintiffs’ claims for consumer fraud, common law fraud, negligent misrepresentation, strict product liability and punitive damages were dismissed, leaving only the negligence and breach of contract causes of actions. On July 29, 2010, the Appellate Division upheld the trial court’s decision decertifying the class. Plaintiffs have filed, and JCP&L has opposed, a motion for leave to appeal to the New Jersey Supreme Court. JCP&L is waiting forIn November 2010, the Supreme Court issued an order denying Plaintiffs’ motion. The Court’s decision.
Litigation Relating toorder effectively ends the Proposed Allegheny Energy Merger
In connection with the proposed merger (Note 16), purported shareholders of Allegheny Energy have filed putative shareholder class action and/or derivative lawsuits against Allegheny Energyattempt, and its directors and certain officers, referredleaves only nine (9) plaintiffs to as the Allegheny Energy defendants, FirstEnergy and Merger Sub. Four putative class action and derivative lawsuits were filed in the Circuit Court for Baltimore City, Maryland (Maryland Court). One was withdrawn.pursue their respective individual claims. The Maryland Court has consolidated the remaining three cases under the caption: In re Allegheny Energy Shareholder and Derivative Litigation, C.A. No. 24-C-10-1301. Three shareholder lawsuits were filed in the Court of Common Pleas of Westmoreland County, Pennsylvania and the court has consolidated these actions under the caption: In re Allegheny Energy, Inc. Shareholder Class and Derivative, Litigation, Lead Case No. 1101 of 2010. One putative shareholder class action was filed in the U.S. District Court for the Western District of Pennsylvania and is captioned Louisiana Municipal Police Employees’ Retirement System v. Evanson, et al., C.A. No. 10-319 NBF. In summary, the lawsuits allege, among other things, that the Allegheny Energy directors breachedindividual plaintiffs have yet to take any affirmative steps to pursue their fiduciary duties by approving the merger agreement, and that Allegheny Energy, FirstEnergy and Merger Sub aided and abetted in these alleged breaches of fiduciary duty. The complaints seek, among other things, jury trials, money damages and injunctive relief. While FirstEnergy believes the lawsuits are without merit and has defended vigorously against the claims, in order to avoid the costs associated with the litigation, the defendants have agreed to the terms of a disclosure-based settlement of all these shareholder lawsuits and have reached agreement with counsel for all of the plaintiffs concerning fee applications. Under the terms of the settlement, no payments are being made by FirstEnergy or Merger Sub. A formal stipulation of settlement was filed with the Maryland Court on October 18, 2010 and agreements have been signed with plaintiffs in the Pennsylvania proceedings to dismiss those actions once the settlement is approved by the Maryland Court. The Maryland judge has preliminarily approved the stipulation of settlement and set the final approval hearing date for December 13, 2010. If the parties are unable to obtain final approval of the settlement, then litigation will proceed, and the outcome of any such litigation is inherently uncertain. If a dismissal is not granted or a settlement is not reached, these lawsuits could prevent or delay the completion of the merger and result in substantial costs to FirstEnergy. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger closes may adversely affect FirstEnergy’s business, financial condition or results of operations.individual claims.
Nuclear Plant Matters
During a planned refueling outage that began on February 28, 2010, FENOC conducted a non destructive examination and testing of the Control Rod Drive Mechanism (CRDM) nozzles of the Davis-Besse reactor pressure vessel head. FENOC identified flaws in CRDM nozzles that required modification. The NRC was notified of these findings, along with federal, state and local officials. On March 17, 2010, the NRC sent a special inspection team to Davis-Besse to assess the adequacy of FENOC’s identification, analyses and resolution of the CRDM nozzle flaws and to ensure acceptable modifications were made prior to placing the RPV head back in service. After successfully completing the modifications, FENOC committed to take a number of corrective actions including strengthening leakage monitoring procedures and shutting Davis-Besse down no later than October 1, 2011, to replace the reactor pressure vessel head with nozzles made of material less susceptible to primary water stress corrosion cracking, further enhancing the safe and reliable operations of the plant. On June 29, 2010, FENOC returned Davis-Besse to service. On September 9, 2010, the NRC held a public exit meeting describing the results of the NRC special inspection team inspection of FENOC’s identification of the CRDM nozzles with flaws and the modifications to those nozzles. On October 22, 2010, the NRC issued its final report of the special inspection. The report contained three findings characterized as very low safety significance that were promptly corrected prior to plant operation.

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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 SeptemberJune 30, 2010,2011, FirstEnergy had approximately $2.0$2 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As required by the NRC, FirstEnergy providesannually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy’s NDT fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy’s obligation to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the NDT. The NRC issued guidance anticipating an additional $15increase in low-level radioactive waste disposal costs associated with the decommissioning of nuclear facilities. On March 28, 2011, FENOC submitted its biennial report on nuclear decommissioning funding to the NRC. This submittal identified a total shortfall in nuclear decommissioning funding for Beaver Valley Unit 1 and Perry of approximately $92.5 million. On June 24, 2011, FENOC submitted a $95 million parental guarantee associatedto the NRC for its approval.

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In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse Nuclear Power Station operating license for an additional twenty years, until 2037. By an order dated April 26, 2011, a NRC Atomic Safety and Licensing Board (ASLB) granted a hearing on the Davis-Besse license renewal application to a group of petitioners. By this order, the ASLB also admitted two contentions challenging whether FENOC’s Environmental Report adequately evaluated (1) a combination of renewable energy sources as alternatives to the renewal of Davis-Besse’s operating license, and (2) severe accident mitigation alternatives at Davis-Besse. On May 6, 2011, FENOC filed an appeal with the fundingNRC Commissioners from the order granting a hearing on the Davis-Besse license renewal application.
On April 14, 2011, a group of decommissioningenvironmental organizations petitioned the NRC Commissioners to suspend certain pending nuclear licensing proceedings, including the Davis-Besse license renewal proceeding, to ensure that any safety and environmental implications of the accident at the Fukushima Daiichi Nuclear Power Station in Japan are considered. By May 2, 2011, the NRC Staff, FENOC and much of the nuclear industry filed responses opposing the petition. On May 6, 2011, petitioners filed a supplemental reply.
In January 2004, subsidiaries of FirstEnergy filed a lawsuit in the U.S. Court of Federal Claims seeking damages in connection with costs incurred at the Beaver Valley, Davis-Besse and Perry Nuclear facilities as a result of the DOE failure to begin accepting spent nuclear fuel on January 31, 1998. DOE was required to so commence accepting spent nuclear fuel by the Nuclear Waste Policy Act (42 USC 10101 et seq) and the contracts entered into by the DOE and the owners and operators of these facilities pursuant to the Act. On January 18, 2011, the parties, FirstEnergy and DOJ, filed a joint status report that established a schedule for the litigation of these claims. FirstEnergy filed damages schedules and disclosures with the DOJ on February 11, 2011, seeking approximately $57 million in damages for delay costs incurred through September 30, 2010. The damage claim is subject to review and audit by DOE.
ICG Litigation
On December 28, 2006, AE Supply and MP filed a complaint in the Court of Common Pleas of Allegheny County, Pennsylvania against International Coal Group, Inc. (ICG), Anker West Virginia Mining Company, Inc. (Anker WV), and Anker Coal Group, Inc. (Anker Coal). Anker WV entered into a long term Coal Sales Agreement with AE Supply and MP for the supply of coal to the Harrison generating facility. Prior to the time of trial, ICG was dismissed as a defendant by the Court, which issue can be the subject of a future appeal. As a result of defendants’ past and continued failure to supply the contracted coal, AE Supply and MP have incurred and will continue to incur significant additional costs for these units.purchasing replacement coal. A non-jury trial was held from January 10, 2011 through February 1, 2011. At trial, AE Supply and MP presented evidence that they have incurred in excess of $80 million in damages for replacement coal purchased through the end of 2010 and will incur additional damages in excess of $150 million for future shortfalls. Defendants primarily claim that their performance is excused under a force majeure clause in the coal sales agreement and presented evidence at trial that they will continue to not provide the contracted yearly tonnage amounts. On May 2, 2011, the court entered a verdict in favor of AE Supply and MP for $104 million ($90 million in future damages and $14 million for replacement coal / interest). Post-trial filings occurred in May 2011, with Oral Argument on June 28, 2011. The parties expect a ruling sometime in the third quarter, at which time the judgment will be final. The parties have 30 days to appeal the final judgment. AE Supply and MP intend to vigorously pursue this matter through appeal if necessary but cannot predict its outcome.
Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.
OnIn February 16, 2010, a class action lawsuit was filed in Geauga County Court of Common Pleas against FirstEnergy, CEI and OE seeking declaratory judgment and injunctive relief, as well as compensatory, incidental and consequential damages, on behalf of a class of customers related to the reduction of a discount that had previously been in place for residential customers with electric heating, electric water heating, or load management systems. The reduction in the discount was approved by the PUCO. OnIn March 18, 2010, the named-defendant companies filed a motion to dismiss the case due to the lack of jurisdiction of the court of common pleas. The court granted the motion to dismiss on September 7, 2010. The plaintiffs appealed the decision to the Court of Appeals of Ohio, which has not yet rendered an opinion.

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There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.
FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy’s or its subsidiaries’ financial condition, results of operations and cash flows.
NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
See Note 1112 of the Combined Notes to the Consolidated Financial Statements (Unaudited) for discussion of new accounting pronouncements.

 

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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 (excluding the Allegheny facilities), and owns FirstEnergy’s nuclear generation facilities, respectively. FENOC, a wholly owned subsidiary of FirstEnergy, operates and maintains the nuclear generating facilities.
FES’ revenues are derived from sales to individual retail customers, sales to communities in the form of governmentgovernmental 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. FESFES’ sales are primarily concentrated in Ohio, Pennsylvania, Illinois, Maryland, Michigan and New Jersey. In 2010, FES also supplied the POLR default service requirements of Met-Ed and Penelec.
The demand for electricity produced and sold by FES, along with the price of that electricity, is impacted by conditions in competitive power markets, global economic activity, economic activity in the Midwest and Mid-Atlantic regions and weather conditions.
For additional information with respect to FES, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Net income decreased by $491$158 million in the first ninesix months of 2010,2011 compared to the same period of 2009.2010. The decrease was primarily due to a $292 million impairment charge ($181 million netlower sales margin, an inventory reserve adjustment, non-core asset impairments and the effect of tax) related to operational changes at certain smaller coal-fired units in response to the continued slow economy, lower demand for electricity and uncertainty related to proposed new federal environmental regulations. In addition, the absence of a $252 million ($158 million after tax) gain in 2009 from the sale of a 9% participation interest in OVEC, lower investment income from the nuclear decommissioning trusts and a decrease in sales margins also contributed to the decline in net income.mark-to-market adjustments.
Revenues
Excluding the impact of the 2009 gain on the OVEC sale, totalTotal revenues increased $836decreased $30 million, or 1%, in the first ninesix months of 2010,2011, compared to the same period of 2009,2010, primarily due to an increasereduced POLR and structured sales, partially offset by growth in direct and governmentgovernmental aggregation sales volumes and sales of RECs, partially offset by decreases in POLR sales to the Ohio Companies and wholesale sales.
The increasedecrease in revenues resulted from the following sources:
                        
 Nine Months    Six Months   
 Ended September 30 Increase  Ended June 30 Increase 
Revenues by Type of Service 2010 2009 (Decrease)  2011 2010 (Decrease) 
 (In millions)  (In millions) 
Direct and Government Aggregation $1,814 $406 $1,408 
POLR 1,911 2,369  (458)
Other Wholesale 322 503  (181)
Direct and Governmental Aggregation $1,765 $1,097 $668 
POLR and Structured Sales 607 1,315  (708)
Wholesale 156 142 14 
Transmission 58 57 1  56 36 20 
RECs 67 — 67  44 67  (23)
Sale of OVEC participation interest — 252  (252)
Other 84 85  (1) 56 57  (1)
              
Total Revenues
 $4,256 $3,672 $584  $2,684 $2,714 $(30)
              
             
  Six Months    
  Ended June 30  Increase 
MWH Sales by Type of Service 2011  2010  (Decrease) 
  (In thousands)     
Direct  21,219   12,857   65.0%
Governmental Aggregation  8,279   5,447   52.0%
POLR and Structured Sales  9,561   25,344   (62.3)%
Wholesale  1,380   1,538   (10.3)%
          
Total Sales
  40,439   45,186   (10.5)%
          

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The increase in direct and governmentgovernmental aggregation revenues of $1,408$668 million resulted from increased revenue from the acquisition of new commercial and industrial customers as well as new governmentgovernmental aggregation contracts with communities in Ohio that provided generation to 1.2approximately 1.5 million residential and small commercial customers at the end of September 2010June 2011 compared to 500,000 suchapproximately 1.1 million customers at the end of September 2009, partially offset by lower unit prices. In addition, sales to residential and small commercial customers were bolstered by weather in the delivery area that was 69% warmer than in 2009.June 2010.

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The decrease in POLR revenues of $458$708 million was due to lower sales volumes to Met-Ed and Penelec, primarily due to the absence in 2011 of a 1,300 MW third-party contract associated with serving Met-Ed and Penelec, and reduced sales to the Ohio Companies, and lower unit prices, partially offset by increased sales volumesto non-associated companies and higher unit prices to the Pennsylvania Companies. The lowerCompanies consistent with our business strategy. Participation in POLR auctions and RFPs are expected to continue but the proportion of these sales volumeswill depend on our hedge positions for direct retail and unit prices to the Ohio Companies in 2010 reflected the results of the May 2009 power procurement process. Theaggregation sales.
Wholesale revenues increased revenues from the Pennsylvania Companies resulted from FES supplying Met-Ed and Penelec with volumes previously supplied through a third-party contract and at prices that were slightly higher than in 2009.
Other wholesale revenues decreased $181by $14 million due to reduced volumes and lower prices.higher wholesale prices partially offset by decreased volumes. The lower sales volumes were due to availablethe result of decreased short-term (net hourly positions) transactions in MISO. Additional capacity serving increased retail sales in Ohio. In July 2010, FES entered into financial transactions thatrevenues earned by generating units were partially 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.by losses on financially settled sales.
The following tables summarize the price and volume factors contributing to changes in revenues from generation sales:revenues:
        
 Increase  Increase 
Source of Change in Direct and Government Aggregation (Decrease) 
Source of Change in Direct and Governmental Aggregation (Decrease) 
 (In millions)  (In millions) 
Direct Sales:  
Effect of increase in sales volumes $909  $493 
Change in prices  (73)  (20)
      
 836  473 
      
Government Aggregation 
 
Governmental Aggregation: 
Effect of increase in sales volumes 570  176 
Change in prices 2  19 
      
 572  195 
      
Net Increase in Direct and Gov’t Aggregation Revenues
 $1,408 
Net Increase in Direct and Governmental Aggregation Revenues
 $668 
      
        
 Increase  Increase 
Source of Change in Wholesale Revenues (Decrease) 
Source of Change in POLR Revenues (Decrease) 
 (In millions)  (In millions) 
POLR:  
Effect of decrease in sales volumes $(200) $(819)
Change in prices  (258) 111 
      
  (458) $(708)
      
Other Wholesale: 
Effect of decrease in sales volumes  (147)
Change in prices (34)
   
  (181)
   
Net Decrease in Wholesale Revenues
 $(639)
   
The sale of RECs resulted in gains of $67 million in the nine months ended September 2010.
     
  Increase 
Source of Change in Wholesale Revenues (Decrease) 
Wholesale:    
Effect of increase in sales volumes $(15)
Change in prices  29 
    
  $14 
    
Transmission revenues increased $1by $20 million due primarily to higher MISO congestion revenue, offset by lowerand PJM congestion revenue. The revenues derived from the sale of RECs declined $23 million in the first six months of 2011.
Expenses
Total operating expenses increased $1.2 billionby $199 million in the first ninesix months of 2010,2011, compared with the same period of 2009.2010.

 

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The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first ninesix months of 2010, from2011, compared with the same period last year:
        
 Increase  Increase 
Source of Change in Fuel and Purchased Power (Decrease)  (Decrease) 
 (In millions)  (In millions) 
Fossil Fuel:  
Change due to increased unit costs $30  $2 
Change due to volume consumed 135   (29)
      
 165   (27)
      
 
Nuclear Fuel:  
Change due to increased unit costs 23  14 
Change due to volume consumed 3  1 
      
 26  15 
      
 
Non-affiliated Purchased Power:  
Power contract mark-to-market adjustment 43 
Change due to decreased unit costs  (84)
Change due to increased unit costs 108 
Change due to volume purchased 650   (242)
   
     (134)
 609    
    
Affiliated Purchased Power:  
Change due to increased unit costs 81  34 
Change due to volume purchased 15   (30)
      
 96  4 
      
Net Increase in Fuel and Purchased Power Costs
 $896 
Net Decrease in Fuel and Purchased Power Costs
 $(142)
      
FossilTotal fuel costs increased $165decreased by $12 million in the first ninesix months of 2010,2011, compared to the same period of 2009,2010, as a result of reduced generation at the fossil units, partially offset by higher generation volumes consumed combined withfossil unit costs. Fossil unit prices increased unit prices. Increased volume reflects higher generation in the first nine months of 2010, compared to the same period last year due to improving economic conditions. The increased costs reflect higher coal and transportation charges in the first nine months of 2010, compared to the same period last year. Nuclear fuel costs increased $26 million primarily due to the replacement of nuclearincreased coal transportation costs. Nuclear fuel atexpenses increased primarily due to higher unit costsprices following the refueling outages that occurred in 2009.2010.
Non-affiliated purchased power costs increased $609 million due primarily to higher volumes purchased and a power contract mark-to-market adjustment, partially offsetdecreased by lower unit costs. The increase in volume primarily relates to the assumption of a 1,300 MW third party contract from Met-Ed and Penelec. Affiliated purchased power increased $96 million primarily due to higher unit costs combined with higher volumes purchased from affiliated companies.
Other operating expenses increased $25$134 million in the first ninesix months of 2010,2011, compared to the same period of 2009, primarily2010, due to lower volumes purchased partially offset by higher unit costs. The decrease in volume relates to the absence in 2011 of a 1,300 MW third-party contract associated with serving Met-Ed and Penelec in the first half of 2011. Affiliated purchased power costs increased transmission expenses ($36 million), from $111by $4 million in the first ninesix months of 20092011, compared to $147the same period of 2010, due to higher unit costs, partially offset by decreased volumes purchased.
Other operating expenses increased by $302 million in the first six months of 2011, compared to the same time period of 2010 primarily due to the following:
Transmission expenses increased sales volumesby $176 million due primarily to increases in PJM of $198 million from higher congestion, network, and increased uncollectible customer accounts and agent fees ($22 million) associated with the growth in direct and government aggregation sales,line loss expense, partially offset by lower nuclear ($39 million) and fossil ($18 million) operating costs. MISO transmission expenses of $22 million.
Nuclear operating costs decreasedincreased by $48 million due primarily due to lower labor, consultinghaving two refueling outages, Perry and contractor costs. The first nine monthsBeaver Valley 2, occurring this year. While Davis-Besse had a refueling outage last year, the work performed during the second quarter of 2010 had one less refueling outage and fewer extended outages than the same period of 2009. was largely capital-related.
Fossil operating costs decreasedincreased by $20 million due primarily due to lowerhigher labor, costs.contractor and material costs resulting from an increase in planned and unplanned outages.
In
A $54 million provision for excess and obsolete material related to revised inventory practices adopted in connection with the first nine month of 2010 impairmentAllegheny merger.
Impairment charges of long-lived assets increased expenses by $294$18 million primarily due to a $292 million impairment charge ($181 million net of tax) related to operational changesimpairments 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 innon-core peaking facilities during the first nine monthsix months of 2010 compared to the same time period of 2009.2011.
General taxes increased $5by $11 million due to sales taxes associated with increased revenues.an increase in revenue-related taxes.
Other Expense
Total other expense increased $128by $17 million in the first ninesix months of 2010,2011, compared to the same period of 2009,2010, primarily due to a decrease in nuclear decommissioning trustcapitalized interest ($24 million) associated with the completion of the Sammis AQC project in 2010, partially offset by increased investment income ($948 million) combined with an increase in interest expense (net of capitalized interest). Interest expense increased primarily due to new long-term debt issued combined with the restructuring of existing PCRBs.from higher NDT income.

 

101133

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 procureOE procures 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: Regulatory Assets, Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Earnings available to parent increaseddecreased by $40$5 million in the first ninesix months of 2010,2011, compared to the same period of 2009.2010. The increasedecrease primarily resulted from lower revenues and higher other operating expenses, partially offset by lower purchased power costs and other operating costs, partially offset by lower revenues and investment income.amortization of regulatory assets.
Revenues
Revenues decreased $589by $171 million, or 29%18%, in the first ninesix months of 2010,2011, compared with the same period in 2009,2010, due primarily to a decrease in generation revenues, partially offset by higher distribution and wholesale generation revenues.
Distribution revenues increased by $31 million in the first six months of 2011, compared to the same period in 2010, due to an increase in KWH deliveries in the residential and industrial sectors and higher average prices in all customer classes. The higher KWH deliveries in the residential class were driven by increased weather-related usage in the first six months of 2011, reflecting a 6% increase in heating degree days. The increase in distribution deliveries to industrial customers was primarily due to recovering economic conditions in OE’s and Penn’s service territory. Higher average prices in all customer classes were principally due to the recovery of deferred distribution costs.
Changes in distribution KWH deliveries and revenues in the first six months of 2011, compared to the same period in 2010, are summarized in the following tables:
Distribution KWH DeliveriesIncrease
Residential3.0%
Commercial0.2%
Industrial3.5%
Increase in Distribution Deliveries
2.4%
     
Distribution Revenues Increase 
  (In millions) 
Residential $19 
Commercial  7 
Industrial  5 
    
Increase in Distribution Revenues
 $31 
    
Retail generation revenues decreased $584by $211 million primarily due to a decrease in KWH sales and lower average prices in all customer classes. Retail generation obligations are attributable to non-shopping customers and are procured through full-requirements auctions. OE defers the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings. Lower KWH sales were primarily the result of a 42% increase inincreased customer shopping, in the first nine months of 2010. That condition is expected to continue to impact the comparative sales levels for the remainder of 2010. Lower KWH sales to residential customers were partially offset by increased weather-related usage in the first ninesix months of 2010, reflecting an 87%2011, as described above. The increase in cooling degree days in OE’s service territory. Decreased volumes were partially offset by higher average prices in thecustomer shopping for residential, commercial and industrial classes. Higher average prices in the commercialcustomer classes was 23%, 14% and industrial classes resulted from the CBP auction for the service period beginning June 1, 2009.8%, respectively.

134

Changes
Decreases in retail generation KWH sales and revenues in the first ninesix months of 2010,2011, compared to the same period in 2009,2010, are summarized in the following tables:
     
Retail Generation KWH Sales Decrease 
     
Residential  (26.030.7)%
Commercial  (60.039.0)%
Industrial  (62.725.4)%
    
Decrease in Retail Generation Sales
  (45.731.2)%
    
        
Retail Generation Revenues Decrease  Decrease 
 (In millions)  (In millions) 
Residential $(166) $(128)
Commercial  (236)  (52)
Industrial  (182)  (31)
      
Decrease in Retail Generation Revenues
 $(584) $(211)
      
Wholesale generation revenues increased $4by $15 million primarilyin the first six months of 2011, compared to the same period of 2010, due to an increase inhigher revenues from sales to FESNGC from OE’s leasehold interests in Perry Unit 1 and Beaver Valley Unit 2, partially offset by lower unit prices.
Distribution revenues decreased $1 million in the first nine months of 2010, compared to the same period in 2009, due to lower commercial and industrial revenues, partially offset by higher residential revenues. Commercial and industrial revenues were primarily impacted by lower average unit prices, resulting from lower transmission rates in 2010. Residential distribution revenues were higher due to higher average unit prices resulting from the 2009 ESP and higher KWH deliveries resulting from the warmer conditions described above. Increased industrial deliveries were the result of an increase in KWH deliveries to major steel customers (42%) and automotive customers (25%), reflecting improving economic conditions.

102

Changes in distribution KWH deliveries and revenues in the first nine months of 2010, compared to the same period in 2009, are summarized in the following tables:
Distribution KWH SalesIncrease
Residential6.3%
Commercial2.1%
Industrial10.6%
Increase in Distribution Deliveries
6.2%
     
  Increase 
Distribution Revenues (Decrease) 
  (In millions) 
Residential $27 
Commercial  (9)
Industrial  (19)
    
Net Decrease in Distribution Revenues
 $(1)
    
2.
Expenses
Total expenses decreased $674by $171 million in the first ninesix months of 2010, from2011, compared to the same period of 2009.2010. The following table presents changes from the prior period by expense category:
        
 Increase  Increase 
Expenses - Changes (Decrease)  (Decrease) 
 (In millions)  (In millions) 
Purchased power costs $(564) $(175)
Other operating expenses  (100) 36 
Amortization of regulatory assets, net  (11)  (36)
General taxes 1  4 
      
Net Decrease in Expenses
 $(674) $(171)
      
Purchased power costs decreased in the first ninesix months of 2010,2011, compared to the same period of 2009, primarily2010, due to lower KWH purchases resulting from reduced generation sales requirements from increased customer shopping in the first ninesix months of 2010 and slightly2011 coupled with lower unit costs. The decreaseincrease in other operating costsexpenses for the first ninesix months of 2010,2011 was primarilyprincipally due to lower MISO transmission expenses ($48 million) (assumed by third party suppliers beginning June 1, 2009) and lower costs associated with regulatory obligations for economic developmentrefueling outages at OE’s leased Perry and energy efficiency programs under OE’s 2009 ESP ($18 million).Beaver Valley Unit 2 that were absent in 2010. The amortization of regulatory assets decreased primarily due to lower MISO transmission cost amortization, partially offset by the recoveryhigher deferred residential generation credits in 2011. General taxes increased as a result of certain regulatory assets.higher property taxes.
Other Expense
Other expense increased $21by $3 million in the first ninesix months of 2010,2011, compared to the same period of 2009, primarily2010 due to lower nuclear decommissioning trust investment income.

 

103135

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: Regulatory Assets, Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Earnings available to parent increased by $93 milliondecreased slightly in the first ninesix months of 2010,2011, compared to the same period of 2009.2010. The increasedecrease in earnings was primarily due to the absence in 2010 of one-time regulatory charges recognized in 2009, and decreasedlower revenues, partially offset by lower purchased power and other operating costs, partially offset by decreased revenues and deferredamortization of regulatory assets.
Revenues
Revenues decreased $406by $183 million, or 30%29%, in the first ninesix months of 2010,2011, compared to the same period of 2009,2010, due to decreasedlower retail generation and distribution revenues.
Distribution revenues decreased $76by $14 million in the first ninesix months of 2010,2011, compared to the same period of 2009,2010, due to lower average unit prices for allthe residential and industrial customer classes, partially offset by increased KWH deliveries in all sectors.to the residential and commercial customer classes. The lower average unit prices were the result of lowerthe absence of transition ratescharges in 2010.2011. Higher KWH deliveries to the residential deliveries resulted fromclass were driven by increased weather-related usage in the first ninesix months of 2010,2011, reflecting a 73%15% increase in coolingheating degree days. Increased industrial deliveries were the result of an increasedays in KWHCEI’s service territory. Lower distribution deliveries to major steelindustrial customers (168%) and automotive customers (12%), reflecting improvingreflected softer economic conditions.conditions in this sector.
Changes in distribution KWH deliveries and revenues in the first ninesix months of 2010,2011, compared to the same period of 2009,2010, are summarized in the following tables:
     
Distribution KWH Sales Increase
Distribution KWH Deliveries(Decrease) 
     
Residential  7.32.2%
Commercial  2.42.9%
Industrial  14.4(3.1)%
    
Increase in Distribution Deliveries
  8.80.6%
    
    
     Increase 
Distribution Revenues Decrease  (Decrease) 
 (In millions)  (In millions) 
Residential $—  $2 
Commercial  (29) 17 
Industrial  (47)  (33)
      
Decrease in Distribution Revenues
 $(76)
Net Decrease in Distribution Revenues
 $(14)
      

136

Retail generation revenues decreased $321by $169 million in the first ninesix months of 2010,2011, compared to the same period of 2009,2010, primarily due to lower KWH sales acrossin all customer classes and lower average unit prices for the commercial and residential customer classes. Customer shopping has increased for residential, commercial and industrial classes by 22%, 13% and 36%, respectively. Retail generation obligations are attributable to non-shopping customers and are procured through full-requirements auctions. CEI defers the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings. Reduced KWH sales were primarily the result of increased customer shopping in the first ninesix months of 2010. That condition is expected to continue to impact the comparative sales levels for the remainder of 2010. Lower KWH sales to residential customers were2011, partially offset by the impact of increased KWH deliveries resulting from the warmer weather conditionsweather-related usage by residential customers as described above. Decreased volumes were partially offset by higherLower average unit prices in allthe residential customer classes. Retail generation prices increased in 2010 as aclass were the result of the CBP auctiongeneration credits in place for the service period beginning June 1, 2009.2011.

104

ChangesDecreases in retail generation sales and revenues in the first ninesix months of 2010,2011, compared to the same period of 2009,2010, are summarized in the following tables:
     
Retail Generation KWH Sales Decrease 
     
Residential  (51.746.6)%
Commercial  (69.444.2)%
Industrial  (47.469.8)%
    
Decrease in Retail Generation Sales
  (54.255.0)%
    
        
Retail Generation Revenues Decrease  Decrease 
 (In millions)  (In millions) 
Residential $(78) $(69)
Commercial  (126)  (46)
Industrial  (117)  (54)
      
Decrease in Retail Generation Revenues
 $(321) $(169)
      
Expenses
Total expenses decreased $561by $173 million in the first ninesix months of 2010,2011, compared to the same period of 2009.2010. The following table presents the change from the prior period by expense category:
        
 Increase  Increase 
Expenses - Changes (Decrease)  (Decrease) 
 (In millions)  (In millions) 
Purchased power costs $(441) $(155)
Other operating costs  (45) 6 
Amortization of regulatory assets, net  (205)  (34)
Deferral of new regulatory assets 135 
General taxes  (5) 10 
      
Net Decrease in Expenses
 $(561) $(173)
      
Purchased power costs decreased in the first ninesix months of 2010, primarily2011 due to lower KWH purchases resulting from reduced 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 ninesix months of 2009 associated with regulatory obligations for economic development and energy efficiency programs.2011. Other operating expenses increased principally due to 2011 inventory valuation adjustments. 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 contemporaneousthe completion of transition cost recovery at the end of 2010 and deferred residential generation credits in 2011, partially offset by increased recovery of purchased powerdeferred distribution costs and the absence in 2011 of renewable energy credit expenses that were deferred in 2010. General taxes decreasedincreased in the first ninesix months of 2010, primarily2011 due to a 2010 favorable tax settlement in Ohio.
Other Expense
Other expense increased $4 million in the first nine months of 2010,property taxes as compared to the same period of 2009 due primarily to lower investment income.2010.

 

105137

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: Regulatory Assets, Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Earnings available to parent increased by $13$3 million in the first ninesix months of 2010,2011, compared to the same period of 2009.2010. The increase was primarily due to decreased net amortization of regulatory assets,resulted from lower purchased power costs and other operating costs,higher cost deferrals, partially offset by an increase in interest expense and decreases inlower revenues and investment income.higher other operating expenses.
Revenues
Revenues decreased $287by $40 million, or 42%16%, in the first ninesix months of 2010,2011, compared to the same period of 2009, primarily2010, due to lowera decrease in retail generation and distribution revenues, partially offset by an increase inhigher distribution revenues and wholesale generation revenues.
Distribution revenues decreased $22increased by $3 million in the first ninesix months of 2010,2011, compared to the same period of 2009, primarily2010, due to lower unit prices,higher residential revenues, partially offset by increasedlower industrial revenues. Residential revenues were the result of higher KWH deliveries to all customer classes. Lowerand average unit prices are primarily due to lower transmission rates. Higherprices. The higher KWH deliveries in the residential class were influenceddriven by increased weather-related usage in the first ninesix months of 2010,2011, reflecting an 84%a 14% increase in heating degree days, partially offset by a 23% decrease in cooling degree days in TE’s service territory. Increased industrial deliveriesIndustrial revenues were the result of an increase inimpacted by lower average unit prices, partially offset by higher KWH deliveries to major automotive customers (29%) and steel customers (27%), reflecting improvingfrom recovering economic conditions.
Changes in distribution KWH deliveries and revenues in the first ninesix months of 2010,2011, compared to the same period of 2009,2010, are summarized in the following tables:
     
Distribution KWH Sales Increase
Distribution KWH Deliveries(Decrease) 
     
Residential  9.84.5%
Commercial  2.2(2.5)%
Industrial  15.53.7%
    
Net Increase in Distribution Deliveries
  10.32.6%
    
        
 Increase  Increase 
Distribution Revenues (Decrease)  (Decrease) 
 (In millions)  (In millions) 
Residential $2  $5 
Commercial  (7) — 
Industrial  (17)  (2)
      
Net Decrease in Distribution Revenues
 $(22)
Net Increase in Distribution Revenues
 $3 
      
Retail generation revenues decreased $282by $53 million in the first ninesix months of 2010,2011, compared to the same period of 2009, primarily2010, due to lower KWH sales across all customer classes and lower unit prices for all customer classes. Retail generation obligations are attributable to industrial customers.non-shopping customers and are procured through full-requirements auctions. TE defers the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings. Lower KWH sales to all customer classes were primarily the result of a 59% increase inincreased customer shopping, in the first nine months of 2010. That condition is expected to continue to impact the comparative sales levels for the remainder of 2010. Lower unit prices for industrial customers were primarily due to the absence of TE’s fuel cost recovery and rate stabilization riders that were effective from January through May 2009, partially offset by increased generation prices resulting from the CBP auction, effective June 1, 2009.weather-related usage as described above. Customer shopping has increased for residential, commercial and industrial classes by 16%, 13% and 5%, respectively.

 

106138

ChangesDecreases in retail generation KWH sales and revenues in the first ninesix months of 2010,2011, compared to the same period of 2009,2010, are summarized in the following tables:
     
Retail Generation KWH Sales Decrease 
     
Residential  (45.128.3)%
Commercial  (72.546.6)%
Industrial  (59.411.7)%
    
Decrease in Retail Generation Sales
  (59.022.6)%
    
        
Retail Generation Revenues Decrease  Decrease 
 (In millions)  (In millions) 
Residential $(57) $(16)
Commercial  (104)  (13)
Industrial  (121)  (24)
      
Decrease in Retail Generation Revenues
 $(282) $(53)
      
Wholesale revenues increased $14by $9 million in the first ninesix months of 2010,2011, compared to the same period of 2009,2010, primarily due to higher revenues from sales to NGC from TE’s leasehold interest in Beaver Valley Unit 2.
Expenses
Total expenses decreased $328by $42 million in the first ninesix months of 2010,2011, compared to the same period of 2009.2010. The following table presents changes from the prior period by expense category:
        
 Increase  Increase 
Expenses - Changes (Decrease)  (Decrease) 
 (In millions)  (In millions) 
Purchased power costs $(263) $(53)
Other operating expenses  (31) 18 
Provision for depreciation 1 
Amortization (deferral) of regulatory assets, net  (35)
Deferral of regulatory assets, net  (8)
General Taxes 1 
      
Net Decrease in Expenses
 $(328) $(42)
      
Purchased power costs decreased in the first ninesix months of 2010,2011, compared to the same period of 2009,2010, due to lower volume as a resultKWH purchases resulting from reduced generation sales requirements in the first six months of decreased KWH sales requirements. Other2011 coupled with lower unit costs. The increase in other operating costs decreasedfor the first six months of 2011 was primarily due to reduced transmission expense (assumed by third party suppliers beginning June 1, 2009), lower costsexpenses associated with regulatory obligations for economic developmentthe 2011 refueling outage at the leased Beaver Valley Unit 2 and energy efficiency programs and decreased labor expenses.an Ohio Supreme Court decision rendered in the second quarter of 2011 favoring a large industrial customer, both of which were absent in 2010. The amortizationdeferral of regulatory assets decreased primarilyreduced expenses due to higher PUCO-approved cost deferrals and lower MISO transmission cost amortization in the first ninesix months of 2010,2011, compared to the same period of 2009.2010.
Other Expense
Other expense increased $17by $2 million in the first ninesix months of 2010,2011, compared to the same period of 2009, primarily2010, due to higher interest expense associated with the April 2009 issuance of $300 million senior secured notes and lower nuclear decommissioning trust investment income.

 

107139

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.
As authorized by JCP&L’s Board of Directors, on May 31, 2011 JCP&L returned $500 million of capital to FirstEnergy Corp., the sole owner of all of the shares of JCP&L’s common stock.
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: Regulatory Assets, 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 increaseddecreased by $34$18 million in the first ninesix months of 2010,2011, compared to the same period of 2009.2010. The increasedecrease was primarily due to higherlower revenues, lowerpartially offset by reductions in purchased power costs, other operating costs and decreased net amortization of regulatory assets, partially offset by increased other operating costs.assets.
Revenues
InRevenues decreased by $190 million, or 13%, in the first ninesix months of 2010, revenues increased $43 million, or 2%,2011 compared to the same period of 2009.2010. The increasedecrease in revenues is primarilywas due to higherlower distribution and retail generation revenues, partially offset by an increase in wholesale generation and other revenues, partially offset by a decrease in retail generation revenues.
Distribution revenues increased $63decreased by $71 million in the first ninesix months of 2010,2011, compared to the same period of 2009,2010, primarily due to higher KWH deliveries inan NJBPU-approved rate adjustment that became effective March 1, 2011, for all customer classes. IncreasedThe lower KWH deliveries to the residential class were influenced by decreased weather-related usage was due to warmer weather and improved economic conditionsin the first six months of 2011, reflecting a 16% decrease in cooling degree days offsetting a 7% increase in heating degree days in JCP&L’s service territory. Decreased composite unit prices in theLower distribution deliveries to commercial and industrial classes partially offset the increased volume.customers reflected soft economic conditions in these sectors.
ChangesDecreases in distribution KWH deliveries and revenues in the first ninesix months of 20102011 compared to the same period of 20092010 are summarized in the following tables:
     
Distribution KWH SalesDeliveries IncreaseDecrease 
     
Residential  10.6(2.5)%
Commercial  2.9(3.3)%
Industrial  3.0(1.8)%
    
IncreaseDecrease in Distribution Deliveries
  6.3(2.7)%
    
        
Distribution Revenues Increase  Decrease 
 (In millions)  (In millions) 
Residential $58  $(33)
Commercial 5   (31)
Industrial —   (7)
      
Increase in Distribution Revenues
 $63 
Decrease in Distribution Revenues
 $(71)
      
Retail generation revenues decreased $54by $132 million due to lower retail generation KWH sales in the commercial and industrialall customer 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 customer shopping. Customer shopping has increased for residential, commercial and industrial classes by 10%, 11% and 4%, respectively. Retail generation obligations are attributable to non-shopping customers and are procured through full-requirements auctions. JCP&L defers the number of shopping customers. Higher KWH salesdifference between retail generation revenues and purchased power costs, resulting in no material effect to the residential class reflected increased weather-related usage resulting from a 60% increase in cooling degree days during the first nine months of 2010.current period earnings.

 

108140

ChangesDecreases in retail generation KWH sales and revenues in the first ninesix months of 2010,2011, compared to the same period of 2009,2010, are summarized in the following tables:
     
Increase
Retail Generation KWH Sales (Decrease)Decrease 
     
Residential  10.1(12.1)%
Commercial  (27.726.2)%
Industrial  (21.424.8)%
    
Net Decrease in Retail Generation Sales
  (5.016.7)%
    
    
 Increase     
Retail Generation Revenues (Decrease)  Decrease 
 (In millions)  (In millions) 
Residential $81  $(68)
Commercial  (127)  (59)
Industrial  (8)  (5)
      
Net Decrease in Retail Generation Revenues
 $(54)
Decrease in Retail Generation Revenues
 $(132)
      
Wholesale generation revenues increased $22by $6 million in the first ninesix months of 2010,2011, compared to the same period of 2009,2010, due primarily to higher wholesalean increase in PJM spot market energy prices.sales.
Other revenues increased by $8 million in the first ninesix months of 2010,2011, compared to the same period of 2009,2010, primarily due to an increaseincreases in PJM network transmission revenues and transition bond revenues as a result of higher KWH deliveries in all customer classes.revenues.
Expenses
Total expenses decreased $18by $163 million in the first ninesix months of 2010,2011, compared to the same period of 2009.2010. The following table presents changes from the prior period by expense category:
        
 Increase  Increase 
Expenses - Changes (Decrease)  (Decrease) 
 (In millions)  (In millions) 
Purchased power costs $(33) $(126)
Other operating costs 19   (6)
Provision for depreciation 5   (3)
Amortization of regulatory assets, net  (12)  (29)
General taxes 3  1 
      
Net Decrease in Expenses
 $(18) $(163)
      
Purchased power costs decreased by $126 million in the first ninesix months of 2010 primarily2011 due to the lower requirements from reduced retail generation KWH sales requirements.sales. Other operating costs increaseddecreased by $6 million in the first ninesix months of 2010 primarily due to major2011 principally from lower storm clean up costs in JCP&L’s service territory, partially offset by a favorable settlement of $7 million for collective bargaining agreement recognized in the second quarter of 2010. Depreciation expense increased due to an increase in depreciable property since the third quarter of 2009.restoration costs. The amortization of regulatory assets decreased in the first nine months of 2010 primarilyby $29 million due to reduced cost recovery under the deferralNJBPU-approved NUG tariffs that became effective March 1, 2011, partially offset by lower storm cost deferrals and the write-off of stormnonrecoverable NUG costs.

 

109141

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 wholesaleprocures power sales agreement with FES,under its Default Service Plan (DSP) in which full requirements products (energy, capacity, ancillary services, and applicable transmission services) are procured through descending clock auctions.
As authorized by Met-Ed’s Board of Directors, Met-Ed returned $150 million of capital to supplyFirstEnergy Corp. on May 31, 2011, the sole owner of all of its energy requirements at fixed prices through the endshares of 2010.Met-Ed’s common stock.
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: Regulatory Assets, Capital Resources and Liquidity, Guarantees and Other Assurances, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Net income increased by $6$10 million in the first ninesix months of 2010,2011, compared to the same period of 2009.2010. The increase was primarily due to increased revenuesdecreased purchased power, other operating expenses and decreased amortization of net regulatory assets partially offset by increased purchased power and other operating expenses.decreased revenues.
Revenues
Revenue increased $147decreased by $279 million, or 12%30%, in the first ninesix months of 20102011 compared to the same period of 2009,2010, reflecting higherlower distribution, andretail generation, revenues, partially offset by a decrease inwholesale generation and transmission revenues.
Distribution revenues increased $82decreased by $154 million in the first ninesix months of 2010,2011, compared to the same period of 2009,2010, primarily due to higherlower rates resulting from the annual update to Met-Ed’s TSC rider effective June 1, 2010, partially offset by lower CTC rates forDSP that began in 2011 that eliminated the residential class. Higher KWH deliveries to industrial customers were due to improving economic conditions in Met-Ed’s service territory. Higher residential and commercialtransmission component from the distribution rate. Slightly higher KWH deliveries reflect increased weather-related usage due to an 8% increase in heating degree days offsetting a 59% increase15% decrease in cooling degree days in the first ninesix months of 2010, partially offset by an 11% decrease in heating degree days for2011, compared to the same period.period in 2010.
Changes in distribution KWH deliveries and revenues in the first ninesix months of 2010,2011, compared to the same period of 2009,2010, are summarized in the following tables:
     
Increase
Distribution KWH Deliveries Increase(Decrease) 
     
Residential  5.00.2%
Commercial  4.4(4.1)%
Industrial  4.03.6%
    
Net Increase in Distribution Deliveries
  4.60.5%
    
        
Distribution Revenues Increase  Decrease 
 (In millions)  (In millions) 
Residential $40  $(58)
Commercial 27   (47)
Industrial 15   (49)
      
Increase in Distribution Revenues
 $82 
Decrease in Distribution Revenues
 $(154)
      
Retail generation revenues increased $36decreased by $10 million in the first ninesix months of 2010,2011 compared to the same period of 2009,2010, due to higher composite unit prices in the residential and commercial customer classes and higherlower 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 toclasses resulting from increased customer shopping. Customer shopping has increased for residential, and commercial customers increased primarily due to weather-related usage described above. Increased customer shopping in the commercial and industrial classes by 1%, 42% and 87%, respectively. The impact of increased customer shopping is partially offset by higher generation rates that reflect the higher KWH salesinclusion of transmission services under the DSP, effective January 1, 2011, for all customer classes. Retail generation obligations are attributable to non-shopping customers and are procured through full-requirements auctions. In 2011, Met-Ed began deferring the difference between retail generation revenues and purchased power costs, resulting in these classes.no material effect to current period earnings.

 

110142

Changes in retail generation KWH sales and revenues in the first ninesix months of 2010,2011, compared to the same period of 2009,2010, are summarized in the following tables:
     
Retail Generation KWH Sales IncreaseDecrease 
     
Residential  5.0(1.0)%
Commercial  2.8(44.7)%
Industrial  1.1(87.6)%
    
IncreaseDecrease in Retail Generation Sales
  3.3(43.1)%
    
    
     Increase 
Retail Generation Revenues Increase  (Decrease) 
 (In millions)  (In millions) 
Residential $30  $88 
Commercial 5   (14)
Industrial 1   (84)
      
Increase in Retail Generation Revenues
 $36 
Net Decrease in Retail Generation Revenues
 $(10)
      
Wholesale revenues increased $42decreased by $105 million in the first ninesix months of 20102011 compared to the same period of 2009,2010 primarily reflecting higher PJMdue to Met-Ed ending certain capacity prices.purchase for resale contracts.
Transmission revenues decreased $13by $11 million in the first ninesix months of 20102011 compared to the same period of 20092010 primarily due to decreased Financial Transmission Rights revenues.the termination of Met-Ed’s TSC rates effective January 1, 2011. Met-Ed defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.
Expenses
Total expenses increased $130decreased $290 million in the first ninesix months of 20102011 compared to the same period of 2009.2010. The following table presents changes from the prior year by expense category:
     
  Increase 
Expenses - Changes (Decrease) 
  (In millions) 
Purchased power costs $78 
Other operating costs  112 
Provision for depreciation  1 
Amortization of regulatory assets, net  (61)
    
Net Increase in Expenses
 $130 
    
Expenses - ChangesDecrease
(In millions)
Purchased power costs$(149)
Other operating costs(95)
Provision for depreciation(1)
Amortization of regulatory assets, net(43)
General taxes(2)
Decrease in Expenses
$(290)
Purchased power costs increased $78decreased by $149 million in the first ninesix months of 20102011 due to an increasea decrease in unit costs and increased KWH purchased to source increased generation sales requirements.requirements, partially offset by higher unit costs. Other operating costs increased $112decreased $95 million in the first ninesix months of 20102011 compared to the same period in 2009 primarily2010 due to higherlower transmission congestion and transmission loss expenses that are now included in the cost of purchased power (see reference to deferral accounting above). Depreciation expense partially offset by increased $1 million due to an increase in depreciable property since September of 2009.costs for energy efficiency programs. The amortization of regulatory assets decreased $61$43 million in the first ninesix months of 20102011 primarily due to higher PJM deferrals resulting from increasedthe termination of transmission costs and reduced amortization from decreasing asset balances.transition tariff riders at the end of 2010. General taxes decreased by $2 million in the first six months of 2011 primarily due to lower gross receipts taxes.
Other Expense
In the first ninesix months of 2010,2011, interest income decreased $4by $2 million due to reduced CTC stranded asset balances.balances compared to the same period of 2010.

 

111143

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 electric transmission and distribution services. Penelec also procures generation servicesservice for those customers electing to retain Penelec as their power supplier. Penelec has a wholesaleprocures power sales agreement with FES, to supply all ofunder its energyDefault Service Plan (DSP) in which full requirements at fixed pricesproducts (energy, capacity, ancillary services and applicable transmission services) are procured through the end of 2010.descending clock auctions.
For additional information with respect to Penelec, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Regulatory Assets, Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Net income increased by $1$2 million in the first ninesix months of 2010,2011, compared to the same period of 2009.2010. The increase was primarily due to higher revenueslower purchased power and net deferral of regulatory assets,other operating costs, partially offset by lower revenues and higher purchased power, other operating costs and interest expense.net amortization of regulatory assets.
Revenues
InRevenues decreased by $193 million, or 25%, in the first ninesix months of 2010, revenues increased $84 million, or 7.8%,2011 compared to the same period of 2009.2010. The increasedecrease in revenue was primarily due to higherlower distribution revenues, retail and wholesale generation revenues, partially offset by lower distribution and transmission revenues.
Distribution revenues decreased by $2$5 million in the first ninesix months of 2010,2011, compared to the same period of 2009,2010, primarily due to a decreaselower rates resulting from the DSP that began in 2011 that eliminated the CTCtransmission component from the distribution rate, in all customer classes, partially offset by an increasea PPUC approved rate adjustment for NUG costs. Higher KWH deliveries to industrial customers were primarily due to recovering economic conditions in Penelec’s service territories, compared to the first six months of 2010. Lower KWH deliveries to residential and commercial customers in the universal service and energy efficiency rates forfirst six months of 2011 reflected lower weather-related usage as cooling degree days were 10% below the residential customer class and increased KWH salessame period in all customer classes.2010.
Changes in distribution KWH deliveries and revenues in the first ninesix months of 2010,2011, compared to the same period of 2009,2010, are summarized in the following tables:
     
Increase
Distribution KWH Deliveries Increase(Decrease) 
     
Residential  4.6(1.2)%
Commercial  4.6(4.7)%
Industrial  6.37.3%
    
Net Increase in Distribution Deliveries
  5.11.4%
    
        
 Increase  Increase 
Distribution Revenues (Decrease)  (Decrease) 
 (In millions)  (In millions) 
Residential $19  $3 
Commercial  (12)  (14)
Industrial  (9) 6 
      
Net Decrease in Distribution Revenues
 $(2) $(5)
      
Retail generation revenues increased $66decreased by $80 million in the first ninesix months of 2010,2011, compared to the same period of 2009, primarily2010, due to higher unit prices andlower KWH sales for all customer classes resulting from increased customer shopping. The increase in customer shopping for residential, commercial and industrial customer classes was 2%, 45% and 81%, respectively. The impact of customer shopping is partially offset by higher generation rates that reflect the inclusion of transmission services under the DSP, effective January 1, 2011, for all customer classes. The higher unit prices were primarily dueRetail generation obligations are attributable to an increasenon-shopping customers and are procured through full-requirements auctions. In 2011, Penelec began deferring the difference between retail generation revenues and purchased power costs, resulting in the generation rate, effective January 1, 2010. Higher KWH salesno material effect to industrial customers were due to improved economic conditions in Penelec’s service territory. Higher KWH sales to residential and commercial customers increased primarily due to weather-related usage, reflecting a 94% increase in cooling degree days in the first nine months of 2010, partially offset by a 10% decrease in heating degree days for the same period.current period earnings.

 

112144

Changes in retail generation KWH sales and revenues in the first ninesix months of 20102011, compared to the same period of 20092010, are summarized in the following tables:
     
Retail Generation KWH Sales IncreaseDecrease 
     
Residential  4.6(2.7)%
Commercial  4.3(47.1)%
Industrial  6.9(87.4)%
    
IncreaseDecrease in Retail Generation Sales
  5.1(47.5)%
    
    
     Increase 
Retail Generation Revenues Increase  (Decrease) 
 (In millions)  (In millions) 
Residential $17  $52 
Commercial 26   (35)
Industrial 23   (97)
      
Increase in Retail Generation Revenues
 $66 
Net Decrease in Retail Generation Revenues
 $(80)
      
Wholesale generation revenues increased $39decreased by $98 million in the first ninesix months of 2010,2011, compared to the same period of 2009,2010, due primarily to higherPenelec no longer purchasing non-NUG capacity for resale to the PJM capacity prices.market beginning in 2011.
Transmission revenues decreased by $13$11 million in the first ninesix months of 2010,2011, compared to the same period of 2009,2010, primarily due to lower Financial Transmission Rights revenue.the termination of Penelec’s TSC rates effective January 1, 2011. Penelec defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.
Expenses
Total expenses increaseddecreased by $71$200 million in the first ninesix months of 2010,2011, as compared with the same period of 2009.2010. The following table presents changes from the prior periodyear by expense category:
        
 Increase  Increase 
Expenses - Changes (Decrease)  (Decrease) 
 (In millions)  (In millions) 
Purchased power costs $111  $(192)
Other operating costs 27   (53)
Amortization of regulatory assets, net 46 
Provision for depreciation 1   (1)
Amortization (deferral) of regulatory assets, net  (66)
General taxes  (2)
      
Net Increase in Expenses
 $71 
Net Decrease in Expenses
 $(200)
      
Purchased power costs increased $111decreased by $192 million in the first ninesix months of 2010,2011, compared to the same period of 2009, primarily2010, due to an increase in unit costs and increaseddecreased KWH purchased to source increased generation sales requirements. Other operating costs increased $27decreased by $53 million in the first ninesix months of 2010, primarily2011, due to higherlower transmission congestion and transmission loss expenses that are now included in the cost of purchased power (see reference to deferral accounting above). The amortization (deferral) of net regulatory assets decreased $66increased by $46 million in the first ninesix months of 2010,2011, primarily due to increased costreduced NUG deferrals resulting from higher transmission expenses and decreased amortizationas a result of regulatory assets resulting from lower CTC revenues. General taxes decreased $2 million primarily due to a favorable ruling on a property tax appeal in the first quarter of 2010.
Other Expense
In the first nine months of 2010, other expense increased $14 million primarily due to anPPUC approved increase in interest expense on long-term debt due to a $500 million debt issuancePenelec’s NUG cost recovery rider in September 2009.
January 2011.

 

113145

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

146

(b) CHANGES IN INTERNAL CONTROLS
During the quarter ended September 30, 2010, there were no changes in the registrants’ internal control over financial reporting that has materially affected, or are reasonably likely to materially affect, the registrants’ internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1.
ITEM 1. LEGAL PROCEEDINGS
Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 9 and 10 of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
ITEM 1A.
ITEM 1A. RISK FACTORS
FirstEnergy’sFor the quarter ended June 30, 2011, there have been no material changes to the risk factors included in our 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 material2010, as modified by changes to thesecertain risk factors disclosed in our Quarterly Report on Form 10-Q for the quarterperiod ended September 30, 2010.March 31, 2011.
ITEM 2.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
(c) FirstEnergy
The table below includes information on a monthly basis regarding purchases made by FirstEnergy of its common stock during the thirdsecond quarter of 2010.2011.
                
                 Period 
 Period  April May June Second Quarter 
 July August September Third Quarter  
Total Number of Shares Purchased(a)
 38,180 43,103 460,312 541,595  213,550 367,422 428,966 1,009,938 
 
Average Price Paid per Share
 $36.41 $37.28 $36.76 $36.78  $38.59 $42.62 $44.44 $42.54 
 
Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs
 — — — —  — — — — 
 
Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
 — — — —  — — — — 
(a) Share amounts reflect purchases on the open market to satisfy FirstEnergy’s obligations to deliver common stock under itsfor some or all of the following: 2007 Incentive Compensation Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan, Director Compensation, Allegheny Energy, Inc. 1998 Long-Term Incentive Plan, Allegheny Energy, Inc. 2008 Long-Term Incentive Plan, Allegheny Energy, Inc, Non-Employee Director Stock Plan, Allegheny Energy, Inc, Amended and Restated Revised Plan for Deferral of Compensation of Directors, and Stock Investment Plan. In addition, such amounts reflect shares tendered by employees to pay the exercise price or withholding taxes upon exercise of stock options granted under the 2007 Incentive Compensation Plan and the Executive Deferred Compensation Plan.
ITEM 5.
ITEM 5. OTHER INFORMATION
Signal Peak and Global Rail Credit FacilityMine Safety
On October 22, 2010,FirstEnergy, through its FEV WMB Loan Ventureswholly-owned subsidiary, has a 50% interest in Global Mining Group LLC, a joint venture that owns Signal Peak which is a company that constructed and WMB Loan Ventures II LLC,operates the entities that own mining andBull Mountain Mine No. 1 (Mine), an underground coal transportation operationsmine 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 guarantyMontana. The operation of the borrowers’ obligationsMine is subject to regulation by the Federal Mine Safety and Health Administration (MSHA) under the facility. In addition, FEVFederal Mine Safety and Health Act of 1977 (Mine Act).
Section 1503 of the other entities that directly own the equity interests in the borrowers have pledged those interestsDodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), which was enacted on July 21, 2010, contains new reporting requirements regarding mine safety, including, to the banks as collateral forextent applicable, disclosing in periodic reports filed under the facility. The loan matures on October 22, 2012. The loan proceeds were used bySecurities Exchange Act of 1934 the borrowers primarily to repay $258 millionreceipt 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.certain notifications from the MSHA.

 

114147

Signal Peak received the following notices of violation and proposed assessments for the Mine under the Mine Act during the three months ended June 30, 2011:
     
  Signal 
  Peak 
Number of significant and substantial violations of mandatory health or safety standards under 104*  30 
Number of orders issued under 104(b)*  — 
Number of citations and orders for unwarrantable failure to comply with mandatory health or safety standards under 104(d)*  — 
Number of flagrant violations under 110(b)(2)*  — 
Number of imminent danger orders issued under 107(a)*  — 
MSHA written notices under Mine Act section 104(e)* of a pattern of violation of mandatory health or safety standards or of the potential to have such a pattern  — 
Pending Mine Safety Commission legal actions (including any contested citations issued)  8 
Number of mining related fatalities  — 
Total dollar value of proposed assessments $6,989 
*References to sections under Mine Act
The facility contains customary representations, warranties, covenants and eventsinclusion of defaults of the borrowers, the guarantors and the pledgors and the foregoing description of the facility is qualifiedthis information 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.is not an admission by FirstEnergy that it controls Signal Peak or that Signal Peak is FirstEnergy’s subsidiary for purposes of Section 1503 or for any other purpose,
More detailed information about the Mine, including safety-related data, can be found at MSHA’s website, www.MSHA.gov. Signal Peak operates the Mine under the MSHA identification number 2401950.
ITEM 6.
ITEM 6. EXHIBITS
Exhibit Number
  
Exhibit Number
     
FirstEnergy  
3.1Amendment to the Amended Articles of Incorporation of FirstEnergy Corp. dated as of February 25, 2011 (incorporated by reference to FirstEnergy’s Form 8-K filed February 25, 2011, Exhibit 3.1, File No. 21011)
    
 10.1  AmendedCredit Agreement, dated as of June 17, 2011, among FirstEnergy Corp. Deferred Compensation Plan for Outside Directors, amended, The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and restatedWest Penn Power Company, as borrowers, the Royal Bank of September 21, 2010.Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.
   10.2 Amended FirstEnergy Corp. Executive Deferred Compensation Plan, amended and restated as of September 21, 2010.
10.3Signal Peak Credit Agreement, including the forms of the guaranty and pledge agreement attached as exhibits thereto
 12  Fixed charge ratios
  
 31.1  Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
   
31.2  Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
  
 32  Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
   
101* The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the period ended SeptemberJune 30, 2010,2011, formatted in XBRL (extensible Business Reporting Language): (i) Consolidated Statements of Income and Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements tagged as blocks of text and (v) document and entity information.

148

Exhibit Number
FES
10.1Credit Agreement, dated as of June 17, 2011, among FirstEnergy Solutions Corp., and Allegheny Energy Supply Company, LLC, as borrowers, JPMorgan Chase Bank, N.A., as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.
12Fixed charge ratios
31.1Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
31.2Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
32Certification 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 Solutions Corp. for the period ended June 30, 2011, formatted in XBRL (extensible Business Reporting Language): (i) Consolidated Statements of Income and Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements tagged as blocks of text and (v) document and entity information.
     
OE  
FES10.1 Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.
     
 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
OE* The following materials from the Quarterly Report on Form 10-Q of Ohio Edison Company. for the period ended June 30, 2011, formatted in XBRL (extensible Business Reporting Language): (i) Consolidated Statements of Income and Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements tagged as blocks of text and (v) document and entity information.
     
CEI 
10.1Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.
 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
CEI* The following materials from the Quarterly Report on Form 10-Q of The Cleveland Electric Illuminating Company. for the period ended June 30, 2011, formatted in XBRL (extensible Business Reporting Language): (i) Consolidated Statements of Income and Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements tagged as blocks of text and (v) document and entity information.

149

     
Exhibit Number 
TE
10.1Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.
 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
TE* The following materials from the Quarterly Report on Form 10-Q of The Toledo Edison Company. for the period ended June 30, 2011, formatted in XBRL (extensible Business Reporting Language): (i) Consolidated Statements of Income and Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements tagged as blocks of text and (v) document and entity information.
     
JCP&L 
10.1Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.
 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
JCP&L* The following materials from the Quarterly Report on Form 10-Q of Jersey Central Power & Light Company. for the period ended June 30, 2011, formatted in XBRL (extensible Business Reporting Language): (i) Consolidated Statements of Income and Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements tagged as blocks of text and (v) document and entity information.
     
Met-Ed 
10.1Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.
 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

 

115150

     
Exhibit Number  
Met-Ed101* The following materials from the Quarterly Report on Form 10-Q of Metropolitan Edison Company. for the period ended June 30, 2011, formatted in XBRL (extensible Business Reporting Language): (i) Consolidated Statements of Income and Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements tagged as blocks of text and (v) document and entity information.
     
Penelec 
10.1Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.
 12  Fixed charge ratios
  
 31.1  Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
   
31.2  Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
  
 32  Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
     
Penelec
 101* 12Fixed charge ratios
31.1CertificationThe following materials from the Quarterly Report on Form 10-Q of chief executive officer,Pennsylvania Electric Company. for the period ended June 30, 2011, formatted in XBRL (extensible Business Reporting Language): (i) Consolidated Statements of Income and Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements tagged as adopted pursuant to Rule 13a-14(a)
31.2
Certificationblocks of chief financial officer, as adopted pursuant to Rule 13a-14(a)
32Certification of chief executive officertext and chief financial officer, pursuant to 18 U.S.C. Section 1350(v) document and entity information.
* 
Users of these data are advised pursuant to Rule 401 of Regulation S-T that the financial information contained in the XBRL-Related Documents is unaudited and, as a result, investors should not rely on the XBRL-Related Documents in making investment decisions. Furthermore, users of these data are advised in accordance with Rule 406T of Regulation S-T promulgated by the Securities and Exchange Commission that this Interactive Data File is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.
Pursuant to reporting requirements of respective financings, FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec are required to file fixed charge ratios as an exhibit to this Form 10-Q.
Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed nor Penelec have filed as an exhibit to this Form 10-Q any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of its respective total assets, but each hereby agrees to furnish to the SEC on request any such documents.

 

116151

SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
October 26, 2010August 2, 2011
     
 
FIRSTENERGY CORP.

Registrant

FIRSTENERGY SOLUTIONS CORP.

Registrant

OHIO EDISON COMPANY

Registrant

THE CLEVELAND ELECTRIC
ILLUMINATING COMPANY

Registrant

THE TOLEDO EDISON COMPANY

Registrant

METROPOLITAN EDISON COMPANY

Registrant

PENNSYLVANIA ELECTRIC COMPANY

Registrant
 		 
 
/s/ Harvey L. Wagner  
 Harvey L. Wagner  
 Vice President, Controller
and Chief Accounting Officer 		 
 
 
JERSEY CENTRAL POWER & LIGHT COMPANY

Registrant
 		 
 /s/ K. Jon Taylor  
 K. Jon Taylor  
 Controller
(Principal Accounting Officer) 		 

 

117152