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 March 31,June 30, 2011
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)
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 AprilJULY 29, 2011 
FirstEnergy Corp., $.10 par value  418,216,437 
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  740,905 
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.
The impact of the regulatory process on the pending matters in the various states in which we do business including, but not limited to, matters related to rates.
The status of the PATH project in light of PJM’s direction to suspend work on the project pending review of its planning process, its re-evaluation of the need for the project and the uncertainty of the timing and amounts of any related capital expenditures.
Business and regulatory impacts from ATSI’s realignment into PJM 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 collect transition and other costs.
Operation and maintenance costs being higher than anticipated.
Other legislative and regulatory changes, and revised environmental requirements, including possible GHG emission, water intake and coal combustion residual regulations, the potential impacts of any laws, rules or regulations that ultimately replace CAIR, including 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 that may arise in connection with any NSR litigation or potential regulatory initiatives or rulemakings (including that such expenditures could result in our decision to shut down or idle certain generating units).
Adverse regulatory or legal decisions and outcomes with respect to our nuclear operations (including, but not limited to the revocation or non-renewal of necessary licenses, approvals or operating permits) and oversightpermits by the NRC including as a result of the incident at Japan’s Fukushima Daiichi Nuclear Plant.Plant).
Adverse legal decisions and outcomes related to Met-Ed’s and Penelec’s ability to recover certain transmission costs through their transmission service charge appeal at the Commonwealth Court of Pennsylvania.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.
Efforts 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, the cost of such capital and overall condition of the capital and credit markets affecting the registrantsFirstEnergy and other FirstEnergyits subsidiaries.
Changes in general economic conditions affecting the registrantsFirstEnergy and other FirstEnergyits 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 continuing uncertainty of the national and regional economy and its impact on the registrants’FirstEnergy’s and its subsidiaries’ major industrial and commercial customers and those of other FirstEnergy subsidiaries.customers.
Issues concerning the soundness of financial institutions and counterparties with which the registrantsFirstEnergy and FirstEnergy’s otherits subsidiaries do business.
Issues arising from the recently completed merger of FirstEnergy and Allegheny Energy, Inc. and the ongoing coordination of their combined operations including FirstEnergy’s 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. 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
  7884 
     
Management’s Narrative Analysis of Results of Operations
    
     
FirstEnergy Solutions Corp.
  117131 
     
Ohio Edison Company
  120134 
     
The Cleveland Electric Illuminating Company
  122136 
     
The Toledo Edison Company
  124138 
     
Jersey Central Power & Light Company
  126140 
     
Metropolitan Edison Company
  128142 
     
Pennsylvania Electric Company
  130144 
     
Item 3. Quantitative and Qualitative Disclosures About Market Risk
  132146 
     
Item 4. Controls and Procedures — FirstEnergy
  132146 
     
Part II. Other Information
    
     
Item 1. Legal Proceedings
  133147 
     
Item 1A. Risk Factors
  133147 
     
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
  134147 
     
Item 5. Other Information
  135147 
     
Item 6. Exhibits
  136148 
     
 Exhibit 10.1
Exhibit 10.5
Exhibit 10.6
Exhibit 10.7
Exhibit 10.8
Exhibit 10.9
Exhibit 10.10
 Exhibit 12
 Exhibit 31.1
 Exhibit 31.2
 Exhibit 32
 EX-101 INSTANCE DOCUMENT
 EX-101 SCHEMA DOCUMENT
 EX-101 CALCULATION LINKBASE DOCUMENT
 EX-101 LABELS LINKBASE DOCUMENT
 EX-101 PRESENTATION LINKBASE DOCUMENT
 EX-101 DEFINITION LINKBASE DOCUMENT

 

ii

GLOSSARY OF TERMS
The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its current and former subsidiaries:
   
AE Allegheny Energy, Inc., a Maryland utility holding company that merged with a subsidiary of FirstEnergy on February 25, 2011
AESC Allegheny Energy Service Corporation, a subsidiary of AE
AE Supply Allegheny Energy Supply Company LLC, an unregulated generation subsidiary of AE
AETAllegheny Energy Transmission, LLC, a parent of TrAIL and PATH
AGC Allegheny Generating Company, a generation subsidiary of AE
Allegheny Allegheny Energy, Inc., together with its consolidated subsidiaries
AVE Allegheny 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 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, that 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
MP Monongahela 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
PATH Potomac-Appalachian Transmission Highline LLC, a joint venture between Allegheny and a subsidiary of American Electric Power Company, Inc.
PATH-VA PATH Allegheny Virginia Transmission Corporation
PE The 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 WP
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 FEV and WMB Loan Ventures LLC, that owns mining operations near Roundup, Montana
TE The Toledo Edison Company, an Ohio electric utility operating subsidiary
TrAIL Trans-Allegheny Interstate Line Company
Utilities OE, CEI, TE, Penn, JCP&L, Met-Ed, Penelec, MP, PE and WP
Utility Registrants OE, CEI, TE, JCP&L, Met-Ed and Penelec
WP West 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:
 
The following abbreviations and acronyms are used to identify frequently used terms in this report:
ALJ Administrative Law Judge
AOCL Accumulated Other Comprehensive Loss
AEP American 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
CDWRCalifornia Department of Water Resources
CO2
Carbon Dioxide
CTCCompetitive Transition Charge

 

iii

GLOSSARY OF TERMS, Cont’d.
   
CCBCoal Combustion By-products
CDWRCalifornia Department of Water Resources
CO2
Carbon Dioxide
CSAPRCross-State Air Pollution Rule
CTCCompetitive Transition Charge
CWAClean Water Act
CWIPConstruction Work in Progress
DCPD Deferred 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)
DSP Default Service Plan
EDCP Executive Deferred Compensation Plan
EE&C Energy Efficiency and Conservation
EIS Energy Insurance Services, Inc.
EMP Energy Master Plan
ENEC Expanded Net Energy Cost
EPA United States Environmental Protection Agency
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
FTRs Financial Transmission Rights
GAAP Generally Accepted Accounting Principles in the United States
RGGI Regional 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
LTIP Long-Term Incentive Plan
MACT Maximum Achievable Control Technology
MDEMaryland Department of the Environment
MDPSC Maryland Public Service Commission
MEIUG Met-Ed Industrial Users Group
MISO Midwest Independent Transmission System Operator, Inc.
Moody’s Moody’s Investors Service, Inc.
MRO Market Rate Offer
MSHA Mine Safety and Health Administration
MTEP MISO Regional Transmission Expansion Plan
MVPMulti-value Project
MW Megawatts
MWH Megawatt-hours
NAAQS National Ambient Air Quality Standards
NDT Nuclear 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
PADEPPA DEP Pennsylvania Department of Environmental Protection
PCRB Pollution Control Revenue Bond
PICA Pennsylvania Intergovernmental Cooperation Authority
PJM PJM Interconnection L. L. C.
POLR Provider of Last Resort; an electric utility’s obligation to provide generation service to customers Whosewhose alternative supplier fails to deliver service
PPUC Pennsylvania Public Utility Commission

iv

GLOSSARY OF TERMS, Cont’d.
PSCWV Public Service Commission of West Virginia
PSA Power Supply Agreement
PSD Prevention of Significant Deterioration
PUCO Public Utilities Commission of Ohio
PURPA Public Utility Regulatory Policies Act of 1978
RECs Renewable Energy Credits
RFP Request for Proposal
RGGI Regional 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
SEC U.S. Securities and Exchange Commission
SIP State Implementation Plan(s) Under the Clean Air Act
SMIP Smart Meter Implementation Plan
SNCR Selective Non-Catalytic Reduction
SO2
 Sulfur Dioxide
SOS Standard Offer Service
TBC Transition Bond Charge
TDS Total Dissolved Solid
TMDL Total Maximum Daily Load
TMI-2 Three Mile Island Unit 2
TSC Transmission Service Charge
VIE Variable Interest Entity
VSCC Virginia State Corporation Commission
WVDEP West Virginia Department of Environmental Protection
WVPSC Public Service Commission of West Virginia

 

v

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
                        
 Three Months Ended  Three Months Six Months 
 March 31  Ended June 30 Ended June 30 
In millions, except per share amounts 2011 2010  2011 2010 2011 2010 
 
REVENUES:
  
Electric utilities $2,332 $2,543  $2,590 $2,373 $4,925 $4,916 
Unregulated businesses 1,244 756  1,470 766 2,711 1,522 
              
Total revenues* 3,576 3,299  4,060 3,139 7,636 6,438 
              
  
EXPENSES:
  
Fuel 453 334  635 350 1,088 684 
Purchased power 1,186 1,238  1,220 1,063 2,406 2,301 
Other operating expenses 1,033 701  1,105 673 2,138 1,374 
Provision for depreciation 220 193  282 190 502 383 
Amortization of regulatory assets 132 212  90 161 222 373 
General taxes 237 205  242 176 479 381 
              
Total expenses 3,261 2,883  3,574 2,613 6,835 5,496 
              
  
OPERATING INCOME
 315 416  486 526 801 942 
              
  
OTHER INCOME (EXPENSE):
  
Investment income 21 16  31 31 52 47 
Interest expense  (231)  (213)  (265)  (207)  (496)  (420)
Capitalized interest 18 41  20 40 38 81 
              
Total other expense  (192)  (156)  (214)  (136)  (406)  (292)
              
  
INCOME BEFORE INCOME TAXES
 123 260  272 390 395 650 
  
INCOME TAXES
 78 111  101 134 179 245 
              
  
NET INCOME
 45 149  171 256 216 405 
  
Loss attributable to noncontrolling interest  (5)  (6)  (10)  (9)  (15)  (15)
              
  
EARNINGS AVAILABLE TO FIRSTENERGY CORP.
 $50 $155  $181 $265 $231 $420 
              
  
BASIC EARNINGS PER SHARE OF COMMON STOCK
 $0.15 $0.51 
     
 
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING
 342 304 
     
 
DILUTED EARNINGS PER SHARE OF COMMON STOCK
 $0.15 $0.51 
     
 
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING
 343 306 
     
 
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
 $0.55 $0.55  — — $0.55 $0.55 
     
   
* Includes $119 and $109 million of excise tax collections of $116 million and $99 million in the three months ended March 31,June 30, 2011 and 2010, respectively, and $235 million and $208 million in the six months ended June 30, 2011 and 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 Ended  Three Months Six Months 
 March 31  Ended June 30 Ended June 30 
(In millions) 2011 2010  2011 2010 2011 2010 
  
NET INCOME
 $45 $149  $171 $256 $216 $405 
              
  
OTHER COMPREHENSIVE INCOME:
  
Pension and other postretirement benefits 19 13  111 17 130 30 
Unrealized gain (loss) on derivative hedges  (6) 4 
Unrealized gain on derivative hedges 17 6 11 10 
Change in unrealized gain on available-for-sale securities 9 6  10 6 19 12 
              
Other comprehensive income 22 23  138 29 160 52 
Income tax expense related to other comprehensive income 1 7  53 9 54 16 
              
Other comprehensive income, net of tax 21 16  85 20 106 36 
              
  
COMPREHENSIVE INCOME
 66 165  256 276 322 441 
  
COMPREHENSIVE LOSS ATTRIBUTABLE TO NONCONTROLLING INTEREST
  (5)  (6)
COMPREHENSIVE LOSS ATTRIBUTABLE
 
TO NONCONTROLLING INTEREST
  (10)  (9)  (15)  (15)
              
  
COMPREHENSIVE INCOME AVAILABLE TO FIRSTENERGY CORP.
 $71 $171  $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)
                
 March 31, December 31,  June 30, December 31, 
(In millions) 2011 2010  2011 2010 
ASSETS
  
  
CURRENT ASSETS:
  
Cash and cash equivalents $1,101 $1,019  $476 $1,019 
Receivables-  
Customers, net of allowance for uncollectible accounts of $38 in 2011 and $36 in 2010 1,636 1,392 
Other, net of allowance for uncollectible accounts of $10 in 2011 and $8 in 2010 229 176 
Materials and supplies 852 638 
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 866 638 
Prepaid taxes 241 199  474 199 
Derivatives 377 182  265 182 
Other 210 92  203 92 
          
 4,646 3,698  4,118 3,698 
          
PROPERTY, PLANT AND EQUIPMENT:
  
In service 38,168 29,451  39,568 29,451 
Less — Accumulated provision for depreciation 11,345 11,180  11,593 11,180 
          
 26,823 18,271  27,975 18,271 
Construction work in progress 2,322 1,517  1,465 1,517 
Property, plant and equipment held for sale, net 490 —  502 — 
          
 29,635 19,788  29,942 19,788 
          
INVESTMENTS:
  
Nuclear plant decommissioning trusts 2,018 1,973  2,051 1,973 
Investments in lease obligation bonds 422 476  414 476 
Nuclear fuel disposal trust 207 208  212 208 
Other 434 345  479 345 
          
 3,081 3,002  3,156 3,002 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Goodwill 6,527 5,575  6,456 5,575 
Regulatory assets 2,084 1,826  2,182 1,826 
Intangible assets 1,075 256  973 256 
Other 818 660  769 660 
          
 10,504 8,317  10,380 8,317 
          
 $47,866 $34,805  $47,596 $34,805 
          
LIABILITIES AND CAPITALIZATION
  
  
CURRENT LIABILITIES:
  
Currently payable long-term debt $1,385 $1,486  $2,058 $1,486 
Short-term borrowings 486 700  656 700 
Accounts payable 1,080 872  1,122 872 
Accrued taxes 412 326  399 326 
Accrued compensation and benefits 312 315  331 315 
Derivatives 425 266  287 266 
Other 1,062 733  691 733 
          
 5,162 4,698  5,544 4,698 
          
CAPITALIZATION:
  
Common stockholders’ equity-  
Common stock, $0.10 par value, authorized 490,000,000 shares- 418,216,437 shares outstanding 42 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 9,779 5,444  9,782 5,444 
Accumulated other comprehensive loss  (1,518)  (1,539)  (1,433)  (1,539)
Retained earnings 4,426 4,609  4,607 4,609 
          
Total common stockholders’ equity 12,729 8,545  12,998 8,545 
Noncontrolling interest  (40)  (32)  (48)  (32)
          
Total equity 12,689 8,513  12,950 8,513 
Long-term debt and other long-term obligations 17,535 12,579  16,491 12,579 
          
 30,224 21,092  29,441 21,092 
          
 
NONCURRENT LIABILITIES:
  
Accumulated deferred income taxes 4,832 2,879  5,219 2,879 
Retirement benefits 2,313 1,868  2,134 1,868 
Asset retirement obligations 1,443 1,407  1,459 1,407 
Deferred gain on sale and leaseback transaction 951 959  942 959 
Power purchase contract liability 606 466 
Adverse power contract liability 649 466 
Other 2,335 1,436  2,208 1,436 
          
 12,480 9,015  12,611 9,015 
          
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
  
 $47,866 $34,805  $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)
                
 Three Months Ended  Six Months Ended 
 March 31  June 30 
(In millions) 2011 2010  2011 2010 
  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income $45 $149  $216 $405 
Adjustments to reconcile net income to net cash from operating activities-  
Provision for depreciation 220 193  502 383 
Amortization of regulatory assets 132 212  222 373 
Nuclear fuel and lease amortization 47 41  92 76 
Deferred purchased power and other costs  (58)  (77)  (168)  (146)
Deferred income taxes and investment tax credits, net 171 59  552 159 
Deferred rents and lease market valuation liability  (15)  (17)  (61)  (62)
Accrued compensation and retirement benefits  (13)  (81) 49  (27)
Commodity derivative transactions, net  (25) 33   (21)  (29)
Pension trust contribution  (157) —   (262) — 
Asset impairments 31 12  41 21 
Cash collateral paid  (28)  (46)
Cash collateral paid, net  (31)  (63)
Interest rate swap transactions — 43 
Decrease (increase) in operating assets-  
Receivables 164 2  199  (156)
Materials and supplies 40  (42) 24  (17)
Prepayments and other current assets 118 33   (268)  (81)
Increase (decrease) in operating liabilities-  
Accounts payable  (90)  (57)  (28) 18 
Accrued taxes  (182) 7   (66)  (58)
Accrued interest 76 66   (4) 10 
Other 15 19  43 9 
          
Net cash provided from operating activities 491 506  1,031 858 
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New financing- 
New Financing- 
Long-term debt 217 —  503 — 
Redemptions and repayments- 
Short-term borrowings, net — 281 
Redemptions and Repayments- 
Long-term debt  (359)  (109)  (1,002)  (407)
Short-term borrowings, net  (214)  (295)  (44) — 
Common stock dividend payments  (190)  (168)  (420)  (335)
Other  (4)  (22)  (76)  (23)
          
Net cash used for financing activities  (550)  (594)  (1,039)  (484)
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (449)  (508)  (1,018)  (997)
Proceeds from asset sales — 114  — 116 
Sales of investment securities held in trusts 969 733  1,703 1,915 
Purchases of investment securities held in trusts  (993)  (755)  (1,807)  (1,934)
Customer acquisition costs  (1)  (101)  (2)  (105)
Cash investments 47 49  50 59 
Cash received in Allegheny merger 590 —  590 — 
Other  (22)  (8)  (51)  (21)
          
Net cash provided from (used for) investing activities 141  (476)
Net cash used for investing activities  (535)  (967)
          
  
Net change in cash and cash equivalents 82  (564)  (543)  (593)
Cash and cash equivalents at beginning of period 1,019 874  1,019 874 
          
Cash and cash equivalents at end of period $1,101 $310  $476 $281 
          
  
SUPPLEMENTAL CASH FLOW INFORMATION:
  
Non-cash transaction: merger with Allegheny, common stock issued $4,354 $—  $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  Three Months Ended Six Months Ended 
 March 31  June 30 June 30 
(In thousands) 2011 2010 
(In millions) 2011 2010 2011 2010 
STATEMENTS OF INCOME
 
  
STATEMENTS OF INCOME
 
REVENUES:
  
Electric sales to non-affiliates $1,044,490 $668,685  $1,052 $729 $2,097 $1,397 
Electric sales to affiliates 260,874 607,302  170 539 431 1,146 
Other 85,724 112,106  70 58 156 171 
              
Total revenues 1,391,088 1,388,093  1,292 1,326 2,684 2,714 
              
  
EXPENSES:
  
Fuel 343,109 328,221  316 343 659 671 
Purchased power from affiliates 68,743 60,953  65 69 134 130 
Purchased power from non-affiliates 296,938 450,216  329 310 626 760 
Other operating expenses 495,935 304,510  429 304 910 608 
Provision for depreciation 68,452 62,918  68 63 136 126 
General taxes 29,105 26,746  30 22 60 49 
Impairment of long-lived assets 13,800 1,833  7 — 20 2 
              
Total expenses 1,316,082 1,235,397  1,244 1,111 2,545 2,346 
              
  
OPERATING INCOME
 75,006 152,696  48 215 139 368 
              
  
OTHER INCOME (EXPENSE):
  
Investment income 5,861 717  16 13 22 14 
Miscellaneous income 19,241 3,143 
Miscellaneous income (expense)  4  4 8 7 
Interest expense — affiliates  (1,017)  (2,305)  (2)  (2)  (3)  (5)
Interest expense — other  (52,960)  (49,644)  (52)  (51)  (105)  (101)
Capitalized interest 9,919 19,690  10 24 20 44 
              
Total other expense  (18,956)  (28,399)  (24)  (12)  (58)  (41)
              
  
INCOME BEFORE INCOME TAXES
 56,050 124,297  24 203 81 327 
  
INCOME TAXES
 20,116 44,371  4 69 25 113 
              
  
NET INCOME
 35,934 79,926  $20 $134 $56 $214 
              
  
Loss attributable to noncontrolling interest  (76) — 
     
 
EARNINGS AVAILABLE TO PARENT
 $36,010 $79,926 
     
 
STATEMENTS OF COMPREHENSIVE INCOME
  
  
NET INCOME
 $35,934 $79,926  $20 $134 $56 $214 
              
  
OTHER COMPREHENSIVE INCOME (LOSS):
 
OTHER COMPREHENSIVE INCOME:
 
Pension and other postretirement benefits 1,512  (9,834) 1 1 3  (9)
Unrealized gain (loss) on derivative hedges  (8,879) 1,274 
Unrealized gain on derivative hedges 14 3 5 4 
Change in unrealized gain on available-for-sale securities 7,807 5,028  8 6 15 11 
              
Other comprehensive income (loss) 440  (3,532)
Income tax benefit related to other comprehensive income  (2,362)  (1,340)
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 2,802  (2,192)
Other comprehensive income, net of tax 13 6 15 4 
              
  
COMPREHENSIVE INCOME
 38,736 77,734  $33 $140 $71 $218 
          
COMPREHENSIVE LOSS ATTRIBUTABLE TO NONCONTROLLING INTEREST
  (76) — 
     
 
COMPREHENSIVE INCOME ATTRIBUTABLE TO PARENT
 $38,812 $77,734 
     
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

 

5

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED BALANCE SHEETS
(Unaudited)
                
 March 31, December 31,  June 30, December 31, 
(In thousands) 2011 2010 
(In millions) 2011 2010 
ASSETS
  
CURRENT ASSETS:
  
Cash and cash equivalents $6,839 $9,281  $6 $9 
Receivables-  
Customers, net of allowance for uncollectible accounts of $18,636 in 2011 and $16,591 in 2010 388,951 365,758 
Customers, net of allowance for uncollectible accounts of $18 in 2011 and $17 in 2010 450 366 
Associated companies 533,280 477,565  490 478 
Other, net of allowances for uncollectible accounts of $6,702 in 2011 and $6,765 in 2010 86,711 89,550 
Other, net of allowances for uncollectible accounts of $3 in 2011 and $7 in 2010 51 90 
Notes receivable from associated companies 478,418 396,770  490 397 
Materials and supplies, at average cost 488,997 545,342  499 545 
Derivatives 328,156 181,660  221 182 
Prepayments and other 50,938 60,171  49 59 
          
 2,362,290 2,126,097  2,256 2,126 
          
PROPERTY, PLANT AND EQUIPMENT:
  
In service 11,239,565 11,321,318  11,455 11,321 
Less — Accumulated provision for depreciation 4,107,542 4,024,280  4,206 4,024 
          
 7,132,023 7,297,038  7,249 7,297 
Construction work in progress 756,305 1,062,744  694 1,063 
Property, plant and equipment held for sale, net 476,602 —  487 — 
          
 8,364,930 8,359,782  8,430 8,360 
          
INVESTMENTS:
  
Nuclear plant decommissioning trusts 1,159,903 1,145,846  1,184 1,146 
Other 9,744 11,704  10 12 
          
 1,169,647 1,157,550  1,194 1,158 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Customer intangibles 131,870 133,968  129 134 
Goodwill 24,248 24,248  24 24 
Property taxes 41,112 41,112  41 41 
Unamortized sale and leaseback costs 90,803 73,386  76 73 
Derivatives 211,223 97,603  135 98 
Other 53,057 48,689  75 48 
          
 552,313 419,006  480 418 
          
 $12,449,180 $12,062,435  $12,360 $12,062 
          
LIABILITIES AND CAPITALIZATION
  
CURRENT LIABILITIES:
  
Currently payable long-term debt $986,863 $1,132,135  $1,088 $1,132 
Short-term borrowings-  
Associated companies 360,543 11,561  541 12 
Other 661 —  1 — 
Accounts payable-  
Associated companies 499,936 466,623  393 467 
Other 189,144 241,191  191 241 
Accrued taxes 66,493 70,129 
Derivatives 380,744 266,411  242 266 
Other 224,525 251,671  262 322 
          
 2,708,909 2,439,721  2,718 2,440 
          
CAPITALIZATION:
  
Common stockholders’ equity- 
Common stockholder’s equity- 
Common stock, without par value, authorized 750 shares- 7 shares outstanding 1,487,565 1,490,082  1,488 1,490 
Accumulated other comprehensive loss  (117,612)  (120,414)  (105)  (120)
Retained earnings 2,454,587 2,418,577  2,474 2,418 
          
Total common stockholders’ equity 3,824,540 3,788,245 
Noncontrolling interest 16  (504)
     
Total equity 3,824,556 3,787,741 
Total common stockholder’s equity 3,857 3,788 
Long-term debt and other long-term obligations 3,144,997 3,180,875  3,000 3,181 
          
 6,969,553 6,968,616  6,857 6,969 
          
NONCURRENT LIABILITIES:
  
Deferred gain on sale and leaseback transaction 950,726 959,154  942 959 
Accumulated deferred income taxes 117,503 57,595  216 58 
Accumulated deferred investment tax credits 53,181 54,224 
Asset retirement obligations 866,643 892,051  875 892 
Retirement benefits 289,285 285,160  295 285 
Property taxes 41,112 41,112 
Lease market valuation liability 205,366 216,695  194 217 
Derivatives 168,409 81,393  85 81 
Other 78,493 66,714  178 161 
          
 2,770,718 2,654,098  2,785 2,653 
          
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
  
 $12,449,180 $12,062,435  $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)
                
 Three Months Ended  Six Months Ended 
 March 31  June 30 
(In thousands) 2011 2010 
(In millions) 2011 2010 
  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income $35,934 $79,926  $56 $214 
Adjustments to reconcile net income to net cash from operating activities-  
Provision for depreciation 68,452 62,918  136 126 
Nuclear fuel and lease amortization 46,653 42,118  92 78 
Deferred rents and lease market valuation liability  (38,759)  (40,869)  (58)  (59)
Deferred income taxes and investment tax credits, net 61,268 37,773  126 114 
Asset impairments 18,791 11,439  28 21 
Accrued compensation and retirement benefits 8 7 
Commodity derivative transactions, net  (35,293) 32,900   (60)  (29)
Cash collateral paid  (27,063)  (21,411)
Cash collateral paid, net  (40)  (38)
Decrease (increase) in operating assets-  
Receivables  (76,069)  (158,288)  (36)  (193)
Materials and supplies 60,633  (8,700) 50  (29)
Prepayments and other current assets 8,728 13,516  12 25 
Increase (decrease) in operating liabilities- 
Decrease in operating liabilities- 
Accounts payable  (18,734)  (41,057)  (124)  (32)
Accrued taxes  (3,164)  (16,300)  (29)  (8)
Accrued interest  (11,845)  (14,930)
Other 4,093 12,069  21 21 
          
Net cash provided from (used for) operating activities 93,625  (8,896)
Net cash provided from operating activities 182 218 
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New financing-  
Long-term debt 150,190 —  247 — 
Short-term borrowings, net 349,643 —  530 76 
Redemptions and repayments-  
Long-term debt  (331,428)  (1,278)  (472)  (295)
Short-term borrowings, net —  (9,237)
Other  (1,017)  (731)  (11)  (1)
          
Net cash provided from (used for) financing activities 167,388  (11,246) 294  (220)
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (159,006)  (301,603)  (334)  (566)
Proceeds from asset sales — 114,272  — 116 
Sales of investment securities held in trusts 215,620 272,094  513 957 
Purchases of investment securities held in trusts  (230,912)  (284,888)  (545)  (979)
Loans from (to) associated companies, net  (81,647) 321,680 
Loans to associated companies, net  (93) 631 
Customer acquisition costs  (1,103)  (100,615)  (2)  (105)
Leasehold improvement payments to associated companies —  (51)
Other  (6,407)  (799)  (18)  (1)
          
Net cash provided from (used for) investing activities  (263,455) 20,141   (479) 2 
          
  
Net change in cash and cash equivalents  (2,442)  (1)  (3) — 
Cash and cash equivalents at beginning of period 9,281 12  9 — 
          
Cash and cash equivalents at end of period $6,839 $11  $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  Three Months Ended Six Months Ended 
 March 31  June 30 June 30 
(In thousands) 2011 2010  2011 2010 2011 2010 
  
STATEMENTS OF INCOME
  
  
REVENUES:
  
Electric sales $363,831 $479,925  $360,203 $415,437 $724,034 $895,362 
Excise and gross receipts tax collections 28,195 28,475  24,941 23,949 53,136 52,424 
              
Total revenues 392,026 508,400  385,144 439,386 777,170 947,786 
              
  
EXPENSES:
  
Purchased power from affiliates 93,262 153,677  69,134 134,050 162,396 287,727 
Purchased power from non-affiliates 60,379 94,231  62,667 78,826 123,046 173,057 
Other operating costs 101,462 88,855 
Other operating expenses 110,778 88,275 212,240 177,130 
Provision for depreciation 21,876 21,880  22,470 22,014 44,346 43,894 
Amortization of regulatory assets, net 774 29,345  2,405 9,424 3,179 38,769 
General taxes 49,426 47,492  45,592 43,362 95,018 90,854 
              
Total expenses 327,179 435,480  313,046 375,951 640,225 811,431 
              
  
OPERATING INCOME
 64,847 72,920  72,098 63,435 136,945 136,355 
              
  
OTHER INCOME (EXPENSE):
  
Investment income 4,308 5,244  5,043 6,309 9,351 11,553 
Miscellaneous income (expense) 290  (292)  (477) 1,295  (187) 1,003 
Interest expense  (22,145)  (22,310)  (22,011)  (22,155)  (44,156)  (44,465)
Capitalized interest 331 208  510 295 841 503 
              
Total other expense  (17,216)  (17,150)  (16,935)  (14,256)  (34,151)  (31,406)
              
  
INCOME BEFORE INCOME TAXES
 47,631 55,770  55,163 49,179 102,794 104,949 
  
INCOME TAXES
 17,491 19,609  16,538 11,856 34,029 31,465 
              
  
NET INCOME
 30,140 36,161  38,625 37,323 68,765 73,484 
      
 
Income attributable to noncontrolling interest 116 132  114 130 230 262 
              
  
EARNINGS AVAILABLE TO PARENT
 $30,024 $36,029  $38,511 $37,193 $68,535 $73,222 
              
  
STATEMENTS OF COMPREHENSIVE INCOME
  
  
NET INCOME
 $30,140 $36,161  $38,625 $37,323 $68,765 $73,484 
              
  
OTHER COMPREHENSIVE INCOME (LOSS):
 
OTHER COMPREHENSIVE INCOME:
 
Pension and other postretirement benefits 339 4,015  1,122 322 1,461 4,337 
Change in unrealized gain on available-for-sale securities  (22) 291 
Increase in unrealized gain on available-for-sale securities 1,591 520 1,569 811 
              
Other comprehensive income 317 4,306  2,713 842 3,030 5,148 
Income tax expense (benefit) related to other comprehensive income  (1,496) 693 
Income tax expense (benefit) related to other 
comprehensive income 386  (26)  (1,110) 667 
              
Other comprehensive income, net of tax 1,813 3,613  2,327 868 4,140 4,481 
              
  
COMPREHENSIVE INCOME
 31,953 39,774  40,952 38,191 72,905 77,965 
  
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST
 116 132 
COMPREHENSIVE INCOME ATTRIBUTABLE TO
 
NONCONTROLLING INTEREST
 114 130 230 262 
              
  
COMPREHENSIVE INCOME AVAILABLE TO PARENT
 $31,837 $39,642  $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)
                
 March 31, December 31,  June 30, December 31, 
(In thousands) 2011 2010  2011 2010 
  
ASSETS
  
CURRENT ASSETS:
  
Cash and cash equivalents $345,030 $420,489  $176 $420,489 
Receivables-  
Customers (net of allowance for uncollectible accounts of $3,774 in 2011 and $4,086 in 2010) 158,146 176,591 
Customers, net of allowance for uncollectible accounts of $3,564 in 2011 and $4,086 in 2010 159,393 176,591 
Associated companies 74,125 118,135  68,709 118,135 
Other 17,290 12,232  32,798 12,232 
Notes receivable from associated companies 16,762 16,957  95,884 16,957 
Prepayments and other 29,366 6,393  35,339 6,393 
          
 640,719 750,797  392,299 750,797 
          
UTILITY PLANT:
  
In service 3,156,648 3,136,623  3,176,455 3,136,623 
Less — Accumulated provision for depreciation 1,217,827 1,207,745  1,230,570 1,207,745 
          
 1,938,821 1,928,878  1,945,885 1,928,878 
Construction work in progress 48,302 45,103  66,656 45,103 
          
 1,987,123 1,973,981  2,012,541 1,973,981 
          
OTHER PROPERTY AND INVESTMENTS:
  
Investment in lease obligation bonds 190,340 190,420  177,835 190,420 
Nuclear plant decommissioning trusts 126,826 127,017  133,354 127,017 
Other 94,604 95,563  92,440 95,563 
          
 411,770 413,000  403,629 413,000 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Regulatory assets 385,005 400,322  392,580 400,322 
Pension assets 59,104 28,596  62,612 28,596 
Property taxes 71,331 71,331  71,331 71,331 
Unamortized sale and leaseback costs 28,877 30,126  27,628 30,126 
Other 16,007 17,634  19,041 17,634 
          
 560,324 548,009  573,192 548,009 
          
 $3,599,936 $3,685,787  $3,381,661 $3,685,787 
          
LIABILITIES AND CAPITALIZATION
  
CURRENT LIABILITIES:
  
Currently payable long-term debt $1,424 $1,419  $1,429 $1,419 
Short-term borrowings-  
Associated companies 103,071 142,116  — 142,116 
Other 320 320  166 320 
Accounts payable-  
Associated companies 96,003 99,421  94,821 99,421 
Other 25,515 29,639  41,417 29,639 
Accrued taxes 68,415 78,707  69,364 78,707 
Accrued interest 25,334 25,382  25,374 25,382 
Other 105,315 74,947  79,795 74,947 
          
 425,397 451,951  312,366 451,951 
          
CAPITALIZATION:
  
Common stockholders’ equity- 
Common stock, without par value, authorized 175,000,000 shares- 60 shares outstanding 951,802 951,866 
Common stockholder’s equity- 
Common stock, without par value, authorized 175,000,000 shares – 60 shares outstanding 783,871 951,866 
Accumulated other comprehensive loss  (177,263)  (179,076)  (174,936)  (179,076)
Retained earnings 71,645 141,621  110,156 141,621 
          
Total common stockholders’ equity 846,184 914,411 
Total common stockholder’s equity 719,091 914,411 
Noncontrolling interest 5,796 5,680  5,313 5,680 
          
Total equity 851,980 920,091  724,404 920,091 
Long-term debt and other long-term obligations 1,152,171 1,152,134  1,151,720 1,152,134 
     
 2,004,151 2,072,225      
      1,876,124 2,072,225 
      
NONCURRENT LIABILITIES:
  
Accumulated deferred income taxes 719,979 696,410  749,687 696,410 
Accumulated deferred investment tax credits 9,799 10,159  9,439 10,159 
Retirement benefits 182,461 183,712  183,345 183,712 
Asset retirement obligations 69,793 74,456  69,164 74,456 
Other 188,356 196,874  181,536 196,874 
          
 1,170,388 1,161,611  1,193,171 1,161,611 
          
COMMITMENTS AND CONTINGENCIES (Note 9)
  
 $3,599,936 $3,685,787  $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)
                
 Three Months Ended  Six Months Ended 
 March 31  June 30 
(In thousands) 2011 2010  2011 2010 
  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income $30,140 $36,161  $68,765 $73,484 
Adjustments to reconcile net income to net cash from operating activities-  
Provision for depreciation 21,876 21,880  44,346 43,894 
Amortization of regulatory assets, net 774 29,345  3,179 38,769 
Purchased power cost recovery reconciliation  (4,926)  (5,908)  (8,584)  (1,514)
Amortization of lease costs 32,933 32,934   (4,696)  (4,619)
Deferred income taxes and investment tax credits, net 26,682  (2,489) 62,216 4,964 
Accrued compensation and retirement benefits  (7,944)  (12,160)  (8,328)  (16,154)
Accrued regulatory obligations  (3,309)  (2,309)
Cash collateral from (to) suppliers, net  (850) 1,215 
Pension trust contribution  (27,000) —   (27,000) — 
Decrease (increase) in operating assets-  
Receivables 82,291 65,141  80,968 49,250 
Prepayments and other current assets  (22,973)  (21,802)  (28,947) 5,072 
Decrease in operating liabilities-  
Accounts payable  (19,625)  (35,461)  (22,253)  (57,208)
Accrued taxes  (10,305)  (15,849)  (9,360)  (25,685)
Accrued interest  (48)  (226)
Other 2,438 9,647  4,261  (114)
          
Net cash provided from operating activities 104,313 101,213  150,408 109,045 
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
Redemptions and repayments- 
Redemptions and Repayments- 
Long-term debt  (110)  (1,363)  (707)  (2,957)
Short-term borrowings, net  (39,045)  (92,863)  (142,270)  (93,017)
Common stock dividend payments  (100,000)  (250,000)  (268,000)  (250,000)
Other —  (113)  (2,340)  (881)
          
Net cash used for financing activities  (139,155)  (344,339)  (413,317)  (346,855)
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (37,651)  (35,680)  (78,894)  (71,698)
Leasehold improvement payments from associated companies — 18,375 
Sales of investment securities held in trusts 7,972 2,424  19,595 59,804 
Purchases of investment securities held in trusts  (8,896)  (2,971)  (25,547)  (64,063)
Loan repayments from associated companies, net 195 14,469 
Loans to associated companies, net  (78,927) 12,420 
Cash investments  (136)  (384) 11,962 11,774 
Other  (2,101) 1,773   (5,593)  (1,298)
          
Net cash used for investing activities  (40,617)  (20,369)  (157,404)  (34,686)
          
  
Net change in cash and cash equivalents  (75,459)  (263,495)  (420,313)  (272,496)
Cash and cash equivalents at beginning of period 420,489 324,175  420,489 324,175 
          
Cash and cash equivalents at end of period $345,030 $60,680  $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  Three Months Ended Six Months Ended 
 March 31  June 30 June 30 
(In thousands) 2011 2010  2011 2010 2011 2010 
  
STATEMENTS OF INCOME
  
REVENUES:
  
Electric sales $206,742 $312,497  $202,148 $280,180 $408,890 $592,677 
Excise tax collections 18,145 17,573  15,706 15,495 33,851 33,068 
              
Total revenues 224,887 330,070  217,854 295,675 442,741 625,745 
              
  
EXPENSES:
  
Purchased power from affiliates 46,168 109,393  36,040 99,422 82,208 208,815 
Purchased power from non-affiliates 18,220 37,398  23,099 32,651 41,319 70,049 
Other operating expenses 35,036 31,235  31,625 28,937 66,661 60,172 
Provision for depreciation 18,426 18,111  18,488 18,336 36,914 36,447 
Amortization of regulatory assets 23,370 45,139 
Amortization of regulatory assets, net 18,166 30,807 41,536 75,946 
General taxes 40,212 38,489  36,954 28,840 77,166 67,329 
              
Total expenses 181,432 279,765  164,372 238,993 345,804 518,758 
              
  
OPERATING INCOME
 43,455 50,305  53,482 56,682 96,937 106,987 
              
  
OTHER INCOME (EXPENSE):
  
Investment income 6,597 7,547  5,637 6,605 12,234 14,152 
Miscellaneous income 636 581  1,038 675 1,674 1,257 
Interest expense  (33,078)  (33,621)  (32,135)  (33,262)  (65,213)  (66,883)
Capitalized interest 27 26  36 7 63 33 
              
Total other expense  (25,818)  (25,467)  (25,424)  (25,975)  (51,242)  (51,441)
              
  
INCOME BEFORE INCOME TAXES
 17,637 24,838  28,058 30,707 45,695 55,546 
  
INCOME TAXES
 4,436 10,843  6,209 8,785 10,645 19,628 
              
  
NET INCOME
 13,201 13,995  21,849 21,922 35,050 35,918 
      
 
Income attributable to noncontrolling interest 366 419  309 366 675 785 
              
  
EARNINGS AVAILABLE TO PARENT
 $12,835 $13,576  $21,540 $21,556 $34,375 $35,133 
              
  
STATEMENTS OF COMPREHENSIVE INCOME
  
  
NET INCOME
 $13,201 $13,995  $21,849 $21,922 $35,050 $35,918 
              
  
OTHER COMPREHENSIVE INCOME (LOSS):
  
Pension and other postretirement benefits 2,967  (22,585)
Income tax benefit related to other comprehensive income  (462)  (8,277)
Pension and other postretirement benefits (charges) 2,975 3,228 5,942  (19,357)
Income tax expense (benefit) related to other comprehensive income 860 976 398  (7,301)
              
Other comprehensive income (loss), net of tax 3,429  (14,308) 2,115 2,252 5,544  (12,056)
              
  
COMPREHENSIVE INCOME (LOSS)
 16,630  (313)
COMPREHENSIVE INCOME
 23,964 24,174 40,594 23,862 
  
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST
 366 419  309 366 675 785 
              
  
TOTAL COMPREHENSIVE INCOME (LOSS) AVAILABLE TO PARENT
 $16,264 $(732)
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)
                
 March 31, December 31,  June 30, December 31, 
(In thousands) 2011 2010  2011 2010 
  
ASSETS
  
 
CURRENT ASSETS:
  
Cash and cash equivalents $30,244 $238  $244 $238 
Receivables-  
Customers (less allowance for doubtful accounts of $3,018 in 2011 and $4,589 in 2010, respectively) 107,418 183,744 
Customers, net of allowance for uncollectible accounts of $2,801 in 2011 and $4,589 in 2010 97,997 183,744 
Associated companies 34,819 77,047  32,348 77,047 
Other 4,848 11,544  13,476 11,544 
Notes receivable from associated companies 22,704 23,236  71,911 23,236 
Materials and supplies, at average cost 13,784 398 
Prepayments and other 13,894 3,656  6,431 3,258 
          
 213,927 299,465  236,191 299,465 
          
UTILITY PLANT:
  
In service 2,407,827 2,396,893  2,417,031 2,396,893 
Less — Accumulated provision for depreciation 937,105 932,246  944,379 932,246 
          
 1,470,722 1,464,647  1,472,652 1,464,647 
Construction work in progress 48,572 38,610  59,281 38,610 
          
 1,519,294 1,503,257  1,531,933 1,503,257 
          
OTHER PROPERTY AND INVESTMENTS:
  
Investment in lessor notes 286,747 340,029  286,745 340,029 
Other 10,035 10,074  10,048 10,074 
          
 296,782 350,103  296,793 350,103 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Goodwill 1,688,521 1,688,521  1,688,521 1,688,521 
Regulatory assets 337,189 370,403  320,337 370,403 
Pension assets 14,652 — 
Property taxes 80,614 80,614  80,614 80,614 
Other 11,176 11,486  12,884 11,486 
          
 2,117,500 2,151,024  2,117,008 2,151,024 
          
 $4,147,503 $4,303,849  $4,181,925 $4,303,849 
          
LIABILITIES AND CAPITALIZATION
  
 
CURRENT LIABILITIES:
  
Currently payable long-term debt $174 $161  $188 $161 
Short-term borrowings- 
Associated companies 23,303 105,996 
Short-term borrowings from associated companies 23,303 105,996 
Accounts payable-  
Associated companies 43,564 32,020  51,001 32,020 
Other 8,811 14,947  18,700 14,947 
Accrued taxes 75,771 84,668  83,265 84,668 
Accrued interest 39,256 18,555  18,551 18,555 
Other 40,862 44,569  38,685 44,569 
          
 231,741 300,916  233,693 300,916 
          
CAPITALIZATION:
  
Common stockholder’s equity-  
Common stock, without par value, authorized 105,000,000 shares- 67,930,743 shares outstanding 886,995 887,087 
Common stock, without par value, authorized 105,000,000 shares, 67,930,743 shares outstanding 887,053 887,087 
Accumulated other comprehensive loss  (149,758)  (153,187)  (147,643)  (153,187)
Retained earnings 531,741 568,906  539,280 568,906 
          
Total common stockholder’s equity 1,268,978 1,302,806  1,278,690 1,302,806 
Noncontrolling interest 14,886 18,017  15,195 18,017 
          
Total equity 1,283,864 1,320,823  1,293,885 1,320,823 
Long-term debt and other long-term obligations 1,831,011 1,852,530  1,831,023 1,852,530 
          
 3,114,875 3,173,353  3,124,908 3,173,353 
          
 
NONCURRENT LIABILITIES:
  
Accumulated deferred income taxes 631,507 622,771  640,059 622,771 
Accumulated deferred investment tax credits 10,784 10,994  10,574 10,994 
Retirement benefits 60,682 95,654  76,010 95,654 
Other 97,914 100,161  96,681 100,161 
          
 800,887 829,580  823,324 829,580 
          
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
 
COMMITMENTS AND CONTINGENCIES (Note 9)
 
 $4,147,503 $4,303,849  $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)
                
 Three Months Ended  Six Months Ended 
 March 31  June 30 
(In thousands) 2011 2010  2011 2010 
  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income $13,201 $13,995  $35,050 $35,918 
Adjustments to reconcile net income to net cash from operating activities-  
Provision for depreciation 18,426 18,111  36,914 36,447 
Amortization of regulatory assets, net 23,370 45,139  41,536 75,946 
Deferred income taxes and investment tax credits, net 4,140  (13,627) 17,221  (18,083)
Accrued compensation and retirement benefits 2,158 2,282  5,421 5,421 
Accrued regulatory obligations  (863)  (26)  (2,001)  (444)
Cash collateral from suppliers, net — 685 
Pension trust contribution  (35,000) —   (35,000) — 
Decrease (increase) in operating assets-  
Receivables 136,887 70,633  140,455 51,757 
Prepayments and other current assets  (10,236)  (9,133)  (17,469) 5,392 
Increase (decrease) in operating liabilities-  
Accounts payable 5,408  (14,387) 10,135  (34,488)
Accrued taxes  (8,898)  (16,616)  (346)  (11,317)
Accrued interest 20,701 20,795 
Other  (3,870)  (2,636)  (4,436) 2,023 
          
Net cash provided from operating activities 165,424 114,530  227,480 149,257 
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
Redemptions and repayments- 
Redemptions and Repayments- 
Long-term debt  (36)  (26)  (74)  (54)
Short-term borrowings, net  (104,228)  (126,334)  (104,228)  (136,013)
Common stock dividend payments  (50,000)  (100,000)  (64,000)  (100,000)
Other  (3,497)  (3,365)  (5,239)  (3,367)
          
Net cash used for financing activities  (157,761)  (229,725)  (173,541)  (239,434)
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (29,334)  (19,735)  (52,743)  (44,373)
Loans to associated companies, net 532 1,426   (48,676) 2,322 
Redemptions of lessor notes 53,282 48,606  53,283 48,608 
Other  (2,137)  (1,085)  (5,797)  (2,365)
          
Net cash provided from investing activities 22,343 29,212 
Net cash provided from (used for) investing activities  (53,933) 4,192 
          
  
Net change in cash and cash equivalents 30,006  (85,983) 6  (85,985)
Cash and cash equivalents at beginning of period 238 86,230  238 86,230 
          
Cash and cash equivalents at end of period $30,244 $247  $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  Three Months Ended Six Months Ended 
 March 31  June 30 June 30 
(In thousands) 2011 2010  2011 2010 2011 2010 
  
STATEMENTS OF INCOME
  
  
REVENUES:
  
Electric sales $106,325 $125,431  $93,048 $114,691 $199,373 $240,122 
Excise tax collections 7,302 7,041  6,270 6,059 13,572 13,100 
              
Total revenues 113,627 132,472  99,318 120,750 212,945 253,222 
              
  
EXPENSES:
  
Purchased power from affiliates 35,517 54,618  17,037 47,106 52,554 101,725 
Purchased power from non-affiliates 13,988 18,491  16,114 15,223 30,102 33,713 
Other operating expenses 36,587 25,545  32,549 25,499 69,136 51,044 
Provision for depreciation 7,931 7,950  7,959 8,013 15,890 15,963 
Deferral of regulatory assets, net  (11,478)  (8,499)  (7,054)  (1,800)  (18,532)  (10,299)
General taxes 14,452 13,461  12,438 12,282 26,890 25,743 
              
Total expenses 96,997 111,566  79,043 106,323 176,040 217,889 
              
  
OPERATING INCOME
 16,630 20,906  20,275 14,427 36,905 35,333 
              
  
OTHER INCOME (EXPENSE):
  
Investment income 2,922 3,800  2,599 5,057 5,521 8,857 
Miscellaneous expense  (1,629)  (1,406)
Miscellaneous income (expense) 396  (945)  (1,233)  (2,351)
Interest expense  (10,443)  (10,487)  (10,415)  (10,455)  (20,858)  (20,942)
Capitalized interest 102 78  135 80 237 158 
              
Total other expense  (9,048)  (8,015)  (7,285)  (6,263)  (16,333)  (14,278)
              
  
INCOME BEFORE INCOME TAXES
 7,582 12,891  12,990 8,164 20,572 21,055 
  
INCOME TAXES
 1,735 5,382  1,429 948 3,164 6,330 
              
  
NET INCOME
 5,847 7,509  11,561 7,216 17,408 14,725 
     
  
Income attributable to noncontrolling interest 2 3  2 2 4 5 
              
  
EARNINGS AVAILABLE TO PARENT
 $5,845 $7,506  $11,559 $7,214 $17,404 $14,720 
              
  
STATEMENTS OF COMPREHENSIVE INCOME
  
  
NET INCOME
 $5,847 $7,509  $11,561 $7,216 $17,408 $14,725 
              
  
OTHER COMPREHENSIVE INCOME:
  
Pension and other postretirement benefits 592 296  575 714 1,167 1,010 
Change in unrealized gain on available-for-sale securities 1,305 369 
Increase (decrease) in unrealized gain on available-for-sale securities 754  (330) 2,059 39 
              
Other comprehensive income 1,897 665  1,329 384 3,226 1,049 
Income tax expense related to other comprehensive income 334 170  351 65 685 235 
              
Other comprehensive income, net of tax 1,563 495  978 319 2,541 814 
              
  
COMPREHENSIVE INCOME
 7,410 8,004  12,539 7,535 19,949 15,539 
  
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST
 2 3  2 2 4 5 
              
  
COMPREHENSIVE INCOME AVAILABLE TO PARENT
 $7,408 $8,001  $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)
                
 March 31, December 31,  June 30, December 31, 
(In thousands) 2011 2010  2011 2010 
  
ASSETS
  
  
CURRENT ASSETS:
  
Cash and cash equivalents $150,014 $149,262  $12 $149,262 
Receivables-  
Customers (net of allowance for uncollectible accounts of $1,209 in 2011 and $1 in 2010) 45,749 29 
Customers, net of allowance for uncollectible accounts of $1,142 in 2011 and $1 in 2010 45,931 29 
Associated companies 56,913 31,777  48,340 31,777 
Other (net of allowance for uncollectible accounts of $343 in 2011 and $330 in 2010) 18,752 18,464 
Other, net of allowance for uncollectible accounts of $339 in 2011 and $330 in 2010 5,272 18,464 
Notes receivable from associated companies 35,489 96,765  128,815 96,765 
Prepayments and other 8,302 2,306  12,052 2,306 
          
 315,219 298,603  240,422 298,603 
          
UTILITY PLANT:
  
In service 952,874 947,203  955,002 947,203 
Less — Accumulated provision for depreciation 449,791 446,401  453,517 446,401 
          
 503,083 500,802  501,485 500,802 
Construction work in progress 12,647 12,604  17,386 12,604 
          
 515,730 513,406  518,871 513,406 
          
OTHER PROPERTY AND INVESTMENTS:
  
Investment in lessor notes 82,133 103,872  82,153 103,872 
Nuclear plant decommissioning trusts 77,141 75,558  79,018 75,558 
Other 1,469 1,492  1,448 1,492 
          
 160,743 180,922  162,619 180,922 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Goodwill 500,576 500,576  500,576 500,576 
Regulatory assets 83,544 72,059  89,112 72,059 
Pension assets 24,427 —  24,603 — 
Property taxes 24,990 24,990  24,990 24,990 
Other 36,167 23,750  42,341 23,750 
          
 669,704 621,375  681,622 621,375 
          
 $1,661,396 $1,614,306  $1,603,534 $1,614,306 
          
LIABILITIES AND CAPITALIZATION
  
  
CURRENT LIABILITIES:
  
Currently payable long-term debt $191 $199  $188 $199 
Accounts payable-  
Associated companies 36,055 17,168  22,144 17,168 
Other 5,238 7,351  12,524 7,351 
Accrued taxes 23,043 24,401  23,699 24,401 
Accrued interest 15,983 5,931  5,933 5,931 
Lease market valuation liability 36,900 36,900  36,900 36,900 
Other 54,905 23,145  18,060 23,145 
          
 172,315 115,095  119,448 115,095 
          
CAPITALIZATION:
  
Common stockholders’ equity- 
Common stock, $5 par value, authorized 60,000,000 shares- 29,402,054 shares outstanding 147,010 147,010 
Common stockholder’s equity- 
Common stock, $5 par value, authorized 60,000,000 shares, 29,402,054 shares outstanding 147,010 147,010 
Other paid-in capital 178,122 178,182  178,157 178,182 
Accumulated other comprehensive loss  (47,620)  (49,183)  (46,642)  (49,183)
Retained earnings 108,379 117,534  100,937 117,534 
          
Total common stockholders’ equity 385,891 393,543 
Total common stockholder’s equity 379,462 393,543 
Noncontrolling interest 2,591 2,589  2,593 2,589 
          
Total equity 388,482 396,132  382,055 396,132 
Long-term debt and other long-term obligations 600,508 600,493  600,524 600,493 
     
 988,990 996,625      
      982,579 996,625 
      
NONCURRENT LIABILITIES:
  
Accumulated deferred income taxes 157,797 132,019  168,429 132,019 
Accumulated deferred investment tax credits 5,822 5,930  5,715 5,930 
Retirement benefits 51,253 71,486  51,764 71,486 
Asset retirement obligations 29,245 28,762  29,737 28,762 
Lease market valuation liability 190,075 199,300  180,850 199,300 
Other 65,899 65,089  65,012 65,089 
          
 500,091 502,586  501,507 502,586 
          
COMMITMENTS AND CONTINGENCIES (Note 9)
 
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
 
 $1,661,396 $1,614,306  $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)
                
 Three Months Ended  Six Months Ended 
 March 31  June 30 
(In thousands) 2011 2010  2011 2010 
  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income $5,847 $7,509  $17,408 $14,725 
Adjustments to reconcile net income to net cash from operating activities-  
Provision for depreciation 7,931 7,950  15,890 15,963 
Deferral of regulatory assets, net  (11,478)  (8,499)  (18,532)  (10,299)
Deferred rents and lease market valuation liability 6,141 6,141   (43,851)  (42,264)
Deferred income taxes and investment tax credits, net 25,046 11,287  41,457 16,503 
Accrued compensation and retirement benefits  (142) 837  1,085 2,600 
Accrued regulatory obligations  (1,193)  (632)
Pension trust contribution  (45,000) —   (45,000) — 
Decrease (increase) in operating assets- 
Cash collateral from (to) suppliers, net  (14) 343 
Increase (decrease) in operating assets- 
Receivables  (70,694) 45,376   (48,807) 52,754 
Prepayments and other current assets  (5,996)  (4,569)  (9,758) 3,608 
Increase (decrease) in operating liabilities-  
Accounts payable 16,774  (35,414) 3,661  (61,195)
Accrued taxes  (1,358)  (4,933)  (701)  (4,007)
Accrued interest 10,052 10,050 
Other 6,098  (4,578) 5,771  (8,960)
          
Net cash provided from (used for) operating activities  (56,779) 31,157 
Net cash used for operating activities  (82,584)  (20,861)
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
Redemptions and repayments- 
Redemptions and Repayments- 
Long-term debt  (56)  (56)  (105)  (111)
Short-term borrowings, net —  (225,975) —  (225,975)
Common stock dividend payments  (15,000)  (130,000)  (34,000)  (130,000)
Other —  (2)  (1,742)  (112)
          
Net cash used for financing activities  (15,056)  (356,033)  (35,847)  (356,198)
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (9,507)  (9,597)  (17,386)  (20,237)
Loan repayments from (loans to) associated companies, net 61,276  (33,587)
Leasehold improvement payments from associated companies — 32,829 
Loans to associated companies, net  (32,050)  (10,818)
Redemptions of lessor notes 21,739 20,509  21,739 20,485 
Sales of investment securities held in trusts 13,883 31,067  28,401 106,814 
Purchases of investment securities held in trusts  (14,338)  (31,705)  (30,050)  (107,978)
Other  (466)  (1,227)  (1,473)  (2,905)
          
Net cash provided from (used for) investing activities 72,587  (24,540)  (30,819) 18,190 
          
  
Net change in cash and cash equivalents 752  (349,416)  (149,250)  (358,869)
Cash and cash equivalents at beginning of period 149,262 436,712  149,262 436,712 
          
Cash and cash equivalents at end of period $150,014 $87,296  $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  Three Months Ended Six Months Ended 
 March 31  June 30 June 30 
(In thousands) 2011 2010  2011 2010 2011 2010 
  
STATEMENTS OF INCOME
  
REVENUES:
  
Electric sales $634,023 $691,392  $576,977 $709,606 $1,211,000 $1,400,998 
Excise tax collections 12,487 12,352  11,120 11,012 23,607 23,364 
              
Total revenues 646,510 703,744  588,097 720,618 1,234,607 1,424,362 
              
  
EXPENSES:
  
Purchased power 370,168 414,016  328,463 410,470 698,631 824,486 
Other operating expenses 86,079 95,660  78,603 75,177 164,682 170,837 
Provision for depreciation 25,314 27,971  26,773 27,093 52,087 55,064 
Amortization of regulatory assets, net 81,587 69,448  40,046 81,326 121,633 150,774 
General taxes 17,411 16,436  15,115 14,902 32,526 31,338 
              
Total expenses 580,559 623,531  489,000 608,968 1,069,559 1,232,499 
              
  
OPERATING INCOME
 65,951 80,213  99,097 111,650 165,048 191,863 
              
  
OTHER INCOME (EXPENSE):
  
Miscellaneous income 1,910 1,833  3,554 1,649 5,464 3,482 
Interest expense  (30,657)  (29,423)  (31,125)  (30,041)  (61,782)  (59,464)
Capitalized interest 427 133  618 156 1,045 289 
              
Total other expense  (28,320)  (27,457)  (26,953)  (28,236)  (55,273)  (55,693)
              
  
INCOME BEFORE INCOME TAXES
 37,631 52,756  72,144 83,414 109,775 136,170 
  
INCOME TAXES
 18,078 23,530  30,383 33,521 48,461 57,051 
              
  
NET INCOME
 $19,553 $29,226  $41,761 $49,893 $61,314 $79,119 
              
  
STATEMENTS OF COMPREHENSIVE INCOME
  
  
NET INCOME
 $19,553 $29,226  $41,761 $49,893 $61,314 $79,119 
              
  
OTHER COMPREHENSIVE INCOME:
  
Pension and other postretirement benefits 4,221 15,928  4,290 4,135 8,511 20,063 
Unrealized gain on derivative hedges 69 69  69 69 138 138 
              
Other comprehensive income 4,290 15,997  4,359 4,204 8,649 20,201 
Income tax expense related to other comprehensive income 1,590 6,558  1,612 1,441 3,202 7,999 
              
Other comprehensive income, net of tax 2,700 9,439  2,747 2,763 5,447 12,202 
              
  
COMPREHENSIVE INCOME
 $22,253 $38,665  $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)
                
 March 31, December 31,  June 30, December 31, 
(In thousands) 2011 2010  2011 2010 
 
ASSETS
  
 
CURRENT ASSETS:
  
Cash and cash equivalents $1 $4  $42 $4 
Receivables-  
Customers (net of allowance for uncollectible accounts of $3,842 in 2011 and $3,769 in 2010) 268,171 323,044 
Customers, net of allowance for uncollectible accounts of $3,306 in 2011 and $3,769 in 2010 259,313 323,044 
Associated companies 27,144 53,780  66,069 53,780 
Other 21,269 26,119  25,580 26,119 
Notes receivable — associated companies 298,274 177,228  16,288 177,228 
Prepaid taxes 10,968 10,889  135,679 10,889 
Other 16,357 12,654  15,421 12,654 
          
 642,184 603,718  518,392 603,718 
          
UTILITY PLANT:
  
In service 4,579,753 4,562,781  4,589,369 4,562,781 
Less — Accumulated provision for depreciation 1,667,017 1,656,939  1,682,577 1,656,939 
          
 2,912,736 2,905,842  2,906,792 2,905,842 
Construction work in progress 78,819 63,535  112,573 63,535 
          
 2,991,555 2,969,377  3,019,365 2,969,377 
          
OTHER PROPERTY AND INVESTMENTS:
  
Nuclear fuel disposal trust 206,833 207,561  212,419 207,561 
Nuclear plant decommissioning trusts 190,424 181,851  190,422 181,851 
Other 2,111 2,104  2,118 2,104 
          
 399,368 391,516  404,959 391,516 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Goodwill 1,810,936 1,810,936  1,810,936 1,810,936 
Regulatory assets 460,156 513,395  469,490 513,395 
Other 25,243 27,938  34,028 27,938 
          
 2,296,335 2,352,269  2,314,454 2,352,269 
          
 $6,329,442 $6,316,880  $6,257,170 $6,316,880 
          
LIABILITIES AND CAPITALIZATION
  
 
CURRENT LIABILITIES:
  
Currently payable long-term debt $32,855 $32,402  $33,315 $32,402 
Short-term borrowings- 
Associated companies 360,917 — 
Other 50,000 — 
Accounts payable-  
Associated companies 16,983 28,571  56,544 28,571 
Other 123,814 158,442  159,720 158,442 
Accrued compensation and benefits 33,415 35,232  35,578 35,232 
Customer deposits 23,494 23,385  23,684 23,385 
Accrued taxes 15,142 2,509  1,346 2,509 
Accrued interest 29,926 18,111  18,059 18,111 
Other 25,663 22,263  13,487 22,263 
          
 301,292 320,915  752,650 320,915 
          
CAPITALIZATION:
  
Common stockholders’ equity- 
Common stockholder’s equity- 
Common stock, $10 par value, authorized 16,000,000 shares- 13,628,447 shares outstanding 136,284 136,284  136,284 136,284 
Other paid-in capital 2,508,754 2,508,874  2,008,847 2,508,874 
Accumulated other comprehensive loss  (250,842)  (253,542)  (248,095)  (253,542)
Retained earnings 246,723 227,170  288,484 227,170 
          
Total common stockholder’s equity 2,640,919 2,618,786  2,185,520 2,618,786 
Long-term debt and other long-term obligations 1,762,365 1,769,849  1,754,582 1,769,849 
          
 4,403,284 4,388,635  3,940,102 4,388,635 
          
NONCURRENT LIABILITIES:
  
Accumulated deferred income taxes 729,478 715,527  761,844 715,527 
Power purchase contract liability 238,677 233,492  239,943 233,492 
Nuclear fuel disposal costs 196,843 196,768  196,868 196,768 
Retirement benefits 175,175 182,364  71,711 182,364 
Asset retirement obligations 110,050 108,297  111,831 108,297 
Other 174,643 170,882  182,221 170,882 
          
 1,624,866 1,607,330  1,564,418 1,607,330 
          
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
  
 $6,329,442 $6,316,880  $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)
                
 Three Months Ended  Six Months Ended 
 March 31  June 30 
(In thousands) 2011 2010  2011 2010 
  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income $19,553 $29,226  $61,314 $79,119 
Adjustments to reconcile net income to net cash from operating activities-  
Provision for depreciation 25,314 27,971  52,087 55,064 
Amortization of regulatory assets, net 81,587 69,448  121,633 150,774 
Deferred purchased power and other costs  (26,516)  (32,775)  (70,998)  (67,664)
Deferred income taxes and investment tax credits, net 25,560  (2,082) 51,222  (1,425)
Accrued compensation and retirement benefits  (4,776)  (5,847) 1,319 2,608 
Cash collateral returned to suppliers  (250)  (23,400)
Cash collateral paid, net  (235)  (23,400)
Pension trust contribution  (105,000) — 
Decrease (increase) in operating assets-  
Receivables 86,359 33,257  58,466  (46,788)
Prepayments and other current assets  (1,687) 16,472 
Prepaid taxes  (124,790)  (111,968)
Increase (decrease) in operating liabilities-  
Accounts payable  (61,612)  (40,992) 13,856 11,924 
Accrued taxes 12,631 50,857   (1,167) 10,368 
Accrued interest 11,815 11,816 
Tax collections payable 7,084 14,544 
Other 7,448 466  612  (6,446)
          
Net cash provided from operating activities 182,510 148,961  58,319 52,166 
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
Redemptions and repayments- 
New Financing- 
Short-term borrowings, net 410,917 57,850 
Redemptions and Repayments- 
Long-term debt  (7,190)  (6,773)  (14,671)  (13,830)
Common stock dividend payments —  (90,000) —  (90,000)
Equity payment to parent  (500,000) — 
Other  (1,452) — 
          
Net cash used for financing activities  (7,190)  (96,773)  (105,206)  (45,980)
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (47,604)  (37,338)  (98,153)  (80,727)
Loans to associated companies, net  (121,046)  (7,620) 160,940 85,049 
Sales of investment securities held in trusts 217,103 190,198  375,885 281,242 
Purchases of investment securities held in trusts  (221,695)  (194,748)  (385,448)  (289,454)
Other  (2,081)  (2,706)  (6,299)  (2,224)
          
Net cash used for investing activities  (175,323)  (52,214)
Net cash provided from (used for) investing activities 46,925  (6,114)
          
  
Net change in cash and cash equivalents  (3)  (26) 38 72 
Cash and cash equivalents at beginning of period 4 27  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  Three Months Ended Six Months Ended 
 March 31  June 30 June 30 
(In thousands) 2011 2010  2011 2010 2011 2010 
 
STATEMENTS OF INCOME
 
 
REVENUES:
  
Electric sales $338,416 $451,560  $265,363 $422,030 $603,779 $873,590 
Gross receipts tax collections 18,800 21,567  14,601 20,629 33,401 42,196 
              
Total revenues 357,216 473,127  279,964 442,659 637,180 915,786 
              
  
EXPENSES:
  
Purchased power from affiliates 49,889 161,080  34,935 149,000 84,824 310,080 
Purchased power from non-affiliates 153,043 91,928  100,836 85,276 253,879 177,204 
Other operating expenses 47,232 101,983  50,075 90,151 97,307 192,134 
Provision for depreciation 12,423 12,758  12,766 13,440 25,189 26,198 
Amortization of regulatory assets, net 32,094 48,800  22,167 48,589 54,261 97,389 
General taxes 22,150 21,740  17,152 19,894 39,302 41,634 
              
Total expenses 316,831 438,289  237,931 406,350 554,762 844,639 
              
  
OPERATING INCOME
 40,385 34,838  42,033 36,309 82,418 71,147 
     
          
OTHER INCOME (EXPENSE):
  
Interest income 93 1,217  13 880 106 2,097 
Miscellaneous income 970 2,173  915 1,381 1,885 3,554 
Interest expense  (13,057)  (13,773)  (13,130)  (13,002)  (26,187)  (26,775)
Capitalized interest 147 126  228 159 375 285 
              
Total other expense  (11,847)  (10,257)  (11,974)  (10,582)  (23,821)  (20,839)
              
  
INCOME BEFORE INCOME TAXES
 28,538 24,581  30,059 25,727 58,597 50,308 
  
INCOME TAXES
 5,951 12,266  13,281 8,618 19,232 20,884 
              
  
NET INCOME
 $22,587 $12,315  $16,778 $17,109 $39,365 $29,424 
              
  
STATEMENTS OF COMPREHENSIVE INCOME
  
  
NET INCOME
 $22,587 $12,315  $16,778 $17,109 $39,365 $29,424 
              
  
OTHER COMPREHENSIVE INCOME:
 
OTHER COMPREHENSIVE INCOME
 
Pension and other postretirement benefits 1,963 9,709  2,227 2,162 4,190 11,871 
Unrealized gain on derivative hedges 84 84  84 84 168 168 
              
Other comprehensive income 2,047 9,793  2,311 2,246 4,358 12,039 
Income tax expense related to other comprehensive income 763 4,177  869 724 1,632 4,901 
              
Other comprehensive income, net of tax 1,284 5,616  1,442 1,522 2,726 7,138 
              
  
COMPREHENSIVE INCOME
 $23,871 $17,931  $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)
                
 March 31, December 31,  June 30, December 31, 
(In thousands) 2011 2010  2011 2010 
 
ASSETS
  
  
CURRENT ASSETS:
  
Cash and cash equivalents $117 $243,220  $157 $243,220 
Receivables-  
Customers (less allowance for doubtful accounts of $3,841 in 2011 and $3,868 in 2010, respectively) 159,801 178,522 
Customers, net of allowance for uncollectible accounts of $3,087 in 2011 and $3,868 in 2010 143,820 178,522 
Associated companies 23,110 24,920  12,849 24,920 
Other 16,836 13,007  16,437 13,007 
Notes receivable from associated companies 9,542 11,028  10,432 11,028 
Prepaid taxes 40,883 343  27,083 343 
Other 1,973 2,289  1,443 2,289 
          
 252,262 473,329  212,221 473,329 
          
UTILITY PLANT:
  
In service 2,260,156 2,247,853  2,266,437 2,247,853 
Less — Accumulated provision for depreciation 852,326 846,003  859,055 846,003 
          
 1,407,830 1,401,850  1,407,382 1,401,850 
Construction work in progress 27,714 23,663  42,604 23,663 
          
 1,435,544 1,425,513  1,449,986 1,425,513 
          
OTHER PROPERTY AND INVESTMENTS:
  
Nuclear plant decommissioning trusts 303,906 289,328  301,188 289,328 
Other 881 884  840 884 
          
 304,787 290,212  302,028 290,212 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Goodwill 416,499 416,499  416,499 416,499 
Regulatory assets 285,300 295,856  341,488 295,856 
Power purchase contract asset 107,055 111,562  65,861 111,562 
Other 51,939 31,699  54,587 31,699 
          
 860,793 855,616  878,435 855,616 
          
 $2,853,386 $3,044,670  $2,842,670 $3,044,670 
          
LIABILITIES AND CAPITALIZATION
  
  
CURRENT LIABILITIES:
  
Currently payable long-term debt $42,450 $28,760  $28,760 $28,760 
Short-term borrowings-  
Associated companies 109,709 124,079  238,399 124,079 
Other 50,000 — 
Accounts payable-  
Associated companies 35,758 33,942  24,377 33,942 
Other 47,450 29,862  48,262 29,862 
Accrued taxes 14,514 60,856  12,844 60,856 
Accrued interest 11,738 16,114  16,011 16,114 
Other 29,543 29,278  29,605 29,278 
          
 291,162 322,891  448,258 322,891 
          
CAPITALIZATION:
  
Common stockholders’ equity- 
Common stock, without par value, authorized 900,000 shares- 740,905 shares outstanding 1,046,970 1,197,076 
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  (141,099)  (142,383)  (139,657)  (142,383)
Retained earnings 29,994 32,406  46,772 32,406 
          
Total common stockholder’s equity 935,865 1,087,099  749,138 1,087,099 
Long-term debt and other long-term obligations 705,125 718,860  704,486 718,860 
          
 1,640,990 1,805,959  1,453,624 1,805,959 
          
NONCURRENT LIABILITIES:
  
Accumulated deferred income taxes 481,530 473,009  494,716 473,009 
Accumulated deferred investment tax credits 6,761 6,866  6,656 6,866 
Nuclear fuel disposal costs 44,465 44,449  44,471 44,449 
Asset retirement obligations 195,883 192,659  199,162 192,659 
Retirement benefits 22,405 29,121  22,276 29,121 
Power purchase contract liability 118,123 116,027  121,924 116,027 
Other 52,067 53,689  51,583 53,689 
          
 921,234 915,820  940,788 915,820 
          
COMMITMENTS AND CONTINGENCIES (Note 9)
        
 $2,853,386 $3,044,670  $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)
                
 Three Months Ended  Six Months Ended 
 March 31  June 30 
(In thousands) 2011 2010  2011 2010 
  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income $22,587 $12,315  $39,365 $29,424 
Adjustments to reconcile net income to net cash from operating activities-  
Provision for depreciation 12,423 12,758  25,189 26,198 
Amortization of regulatory assets, net 32,094 48,800  54,261 97,389 
Deferred costs recoverable as regulatory assets  (12,082)  (18,276)  (41,699)  (38,358)
Deferred income taxes and investment tax credits, net 1,304  (10,308) 11,972  (12,079)
Accrued compensation and retirement benefits  (1,433)  (2,527)  (510)  (1,573)
Cash collateral returned from (paid to) suppliers 1,000  (700)
Pension trust contributions  (35,000) — 
Cash collateral from suppliers, net 174 50 
Pension trust contribution  (35,000) — 
Decrease (increase) in operating assets-  
Receivables 16,702  (5,083) 46,240  (29,439)
Prepayments and other current assets  (40,225)  (52,040)
Prepaid taxes  (26,740)  (31,246)
Increase (decrease) in operating liabilities-  
Accounts payable 15,749  (7,279) 5,148 733 
Accrued taxes  (46,006) 19,960   (47,676) 9,519 
Accrued interest  (4,376)  (5,674)  (103)  (1,277)
Other 6,337 2,373  10,903 7,553 
          
Net cash used for operating activities  (30,926)  (5,681)
Net cash provided from operating activities 41,524 56,894 
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New financing- 
New Financing- 
Short-term borrowings, net — 48,793  164,320 17,898 
Redemptions and repayments- 
Redemptions and Repayments- 
Common stock  (150,000) — 
Long-term debt —  (100,000)  (14,784)  (100,000)
Short-term borrowings, net  (14,369) — 
Common stock  (150,000) — 
Common stock dividend payments  (25,000) —   (80,000) — 
Equity payment to parent  (150,000) — 
          
Net cash used for financing activities  (189,369)  (51,207)  (230,464)  (82,102)
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (21,126)  (25,526)  (46,647)  (54,405)
Sales of investment securities held in trusts 335,860 143,713  501,260 376,610 
Purchases of investment securities held in trusts  (337,632)  (146,056)  (506,220)  (381,219)
Loans repayments from associated companies, net 1,486 85,383 
Loans to associated companies, net 596 85,943 
Other  (1,396)  (618)  (3,112)  (1,715)
          
Net cash provided from (used for) investing activities  (22,808) 56,896   (54,123) 25,214 
          
  
Net increase (decrease) in cash and cash equivalents  (243,103) 8 
Net change in cash and cash equivalents  (243,063) 6 
Cash and cash equivalents at beginning of period 243,220 120  243,220 120 
          
Cash and cash equivalents at end of period $117 $128  $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  Three Months Ended Six Months Ended 
 March 31  June 30 June 30 
(In thousands) 2011 2010  2011 2010 2011 2010 
  
STATEMENTS OF INCOME
  
REVENUES:
  
Electric sales $308,316 $385,936  $238,942 $350,335 $547,258 $736,271 
Gross receipts tax collections 16,529 17,524  12,727 16,162 29,256 33,686 
              
Total revenues 324,845 403,460  251,669 366,497 576,514 769,957 
              
  
EXPENSES:
  
Purchased power from affiliates 47,484 168,400  54,635 152,945 102,119 321,345 
Purchased power from non-affiliates 141,436 91,423  64,459 86,829 205,895 178,252 
Other operating expenses 41,328 72,394  44,570 67,070 85,898 139,464 
Provision for depreciation 14,573 14,682  15,770 16,605 30,343 31,287 
Amortization (deferral) of regulatory assets, net 13,007  (9,966) 12,608  (10,522) 25,615  (20,488)
General taxes 20,736 16,534  14,665 18,647 35,401 35,181 
              
Total expenses 278,564 353,467  206,707 331,574 485,271 685,041 
              
  
OPERATING INCOME
 46,281 49,993  44,962 34,923 91,243 84,916 
              
  
OTHER INCOME (EXPENSE):
  
Miscellaneous income 25 1,613  644 1,310 669 2,923 
Interest expense  (17,234)  (17,290)  (17,361)  (17,630)  (34,595)  (34,920)
Capitalized interest 22 140  41 183 63 323 
              
Total other expense  (17,187)  (15,537)  (16,676)  (16,137)  (33,863)  (31,674)
              
  
INCOME BEFORE INCOME TAXES
 29,094 34,456  28,286 18,786 57,380 53,242 
  
INCOME TAXES
 11,788 17,157  13,568 5,812 25,356 22,969 
              
  
NET INCOME
 $17,306 $17,299  $14,718 $12,974 $32,024 $30,273 
              
  
STATEMENTS OF COMPREHENSIVE INCOME
  
  
NET INCOME
 $17,306 $17,299  $14,718 $12,974 $32,024 $30,273 
              
  
OTHER COMPREHENSIVE INCOME:
  
Pension and other postretirement benefits 1,585 8,547  1,890 1,830 3,475 10,377 
Unrealized gain on derivative hedges 16 16  17 16 33 32 
              
Other comprehensive income 1,601 8,563  1,907 1,846 3,508 10,409 
Income tax expense related to other comprehensive income 555 3,284  678 483 1,233 3,767 
              
Other comprehensive income, net of tax 1,046 5,279  1,229 1,363 2,275 6,642 
              
  
COMPREHENSIVE INCOME
 $18,352 $22,578  $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)
                
 March 31, December 31,  June 30, December 31, 
(In thousands) 2011 2010  2011 2010 
  
ASSETS
  
  
CURRENT ASSETS:
  
Cash and cash equivalents $3 $5  $2 $5 
Receivables-  
Customers (net of allowance for uncollectible accounts of $3,395 in 2011 and $3,369 in 2010) 139,058 148,864 
Customers, net of allowance for uncollectible accounts of $2,856 in 2011 and $3,369 in 2010 121,511 148,864 
Associated companies 16,921 54,052  65,989 54,052 
Other 12,142 11,314  11,420 11,314 
Notes receivable from associated companies 12,334 14,404  13,498 14,404 
Prepaid taxes 47,126 14,026  26,372 14,026 
Other 1,843 1,592  1,423 1,592 
          
 229,427 244,257  240,215 244,257 
          
UTILITY PLANT:
  
In service 2,545,211 2,532,629  2,552,303 2,532,629 
Less — Accumulated provision for depreciation 939,247 935,259  947,315 935,259 
          
 1,605,964 1,597,370  1,604,988 1,597,370 
Construction work in progress 40,799 30,505  62,592 30,505 
          
 1,646,763 1,627,875  1,667,580 1,627,875 
          
OTHER PROPERTY AND INVESTMENTS:
  
Nuclear plant decommissioning trusts 159,999 152,928  162,154 152,928 
Non-utility generation trusts 80,275 80,244  126,786 80,244 
Other 294 297  292 297 
          
 240,568 233,469  289,232 233,469 
          
DEFERRED CHARGES AND OTHER ASSETS:
  
Goodwill 768,628 768,628  768,628 768,628 
Regulatory assets 179,092 163,407  222,804 163,407 
Power purchase contract asset 4,169 5,746  4,000 5,746 
Other 15,140 19,287  15,272 19,287 
          
 967,029 957,068  1,010,704 957,068 
          
 $3,083,787 $3,062,669  $3,207,731 $3,062,669 
          
LIABILITIES AND CAPITALIZATION
  
  
CURRENT LIABILITIES:
  
Currently payable long-term debt $45,000 $45,000  $45,000 $45,000 
Short-term borrowings-  
Associated companies 90,363 101,338  159,902 101,338 
Accounts payable-  
Associated companies 41,231 35,626  77,121 35,626 
Other 33,125 41,420  29,217 41,420 
Accrued taxes 4,262 5,075  3,397 5,075 
Accrued interest 24,069 17,378  17,454 17,378 
Other 23,467 22,541  23,280 22,541 
          
 261,517 268,378  355,371 268,378 
          
CAPITALIZATION:
  
Common stockholders’ equity- 
Common stockholder’s equity- 
Common stock, $20 par value, authorized 5,400,000 shares- 4,427,577 shares outstanding 88,552 88,552  88,552 88,552 
Other paid-in capital 913,439 913,519  913,486 913,519 
Accumulated other comprehensive loss  (162,480)  (163,526)  (161,251)  (163,526)
Retained earnings 58,299 60,993  23,017 60,993 
          
Total common stockholder’s equity 897,810 899,538  863,804 899,538 
Long-term debt and other long-term obligations 1,072,339 1,072,262  1,072,417 1,072,262 
          
 1,970,149 1,971,800  1,936,221 1,971,800 
          
NONCURRENT LIABILITIES:
  
Accumulated deferred income taxes 393,088 371,877  415,899 371,877 
Retirement benefits 187,888 187,621  188,407 187,621 
Power purchase contract liability 121,558 116,972  160,130 116,972 
Asset retirement obligations 99,773 98,132  101,441 98,132 
Other 49,814 47,889  50,262 47,889 
          
 852,121 822,491  916,139 822,491 
          
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
     
 $3,083,787 $3,062,669  $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)
                
 Three Months Ended  Six Months Ended 
 March 31  June 30 
(In thousands) 2011 2010  2011 2010 
  
CASH FLOWS FROM OPERATING ACTIVITIES:
  
Net Income $17,306 $17,299  $32,024 $30,273 
Adjustments to reconcile net income to net cash from operating activities-  
Provision for depreciation 14,573 14,682  30,343 31,287 
Amortization (deferral) of regulatory assets, net 13,007  (9,966) 25,615  (20,488)
Deferred costs recoverable as regulatory assets  (17,771)  (20,461)  (38,291)  (38,955)
Deferred income taxes and investment tax credits, net 16,648 21,772  46,687 42,943 
Accrued compensation and retirement benefits 1,551  (169) 4,733 4,216 
Cash collateral paid, net  (2,124)  (400)  (1,276)  (3,613)
Decrease (increase) in operating assets-  
Receivables 46,100  (4,641) 19,561 3,266 
Prepayments and other current assets  (33,350)  (50,186)
Prepaid taxes  (12,346)  (37,504)
Increase (decrease) in operating liabilities-  
Accounts payable  (8,534)  (1,348) 23,449  (4,603)
Accrued taxes  (813)  (2,142)  (12,373)  (1,339)
Accrued interest 6,691 6,882 
Other 10,204 7,162  13,153 10,227 
          
Net cash provided from (used for) operating activities 63,488  (21,516)
Net cash provided from operating activities 131,279 15,710 
          
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New financing- 
New Financing- 
Long-term debt 25,000 — 
Short-term borrowings, net — 51,334  58,564 25,313 
Redemptions and repayments- 
Short-term borrowings, net  (10,975) — 
Redemptions and Repayments- 
Long-term debt  (25,000) — 
Common stock dividend payments  (20,000) —   (70,000) — 
Other 26  (6)  (1,353) 5 
          
Net cash provided from (used for) financing activities  (30,949) 51,328   (12,789) 25,318 
          
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (31,128)  (27,388)  (64,177)  (58,293)
Loan repayments from associated companies, net 2,070 279 
Loans to associated companies, net 906 498 
Sales of investment securities held in trusts 178,927 93,057  265,223 133,934 
Purchases of investment securities held in trusts  (180,411)  (94,464)  (314,738)  (113,067)
Other  (1,999)  (1,298)  (5,707)  (4,104)
          
Net cash used for investing activities  (32,541)  (29,814)  (118,493)  (41,032)
          
  
Net change in cash and cash equivalents  (2)  (2)  (3)  (4)
Cash and cash equivalents at beginning of period 5 14  5 14 
          
Cash and cash equivalents at end of period $3 $12  $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 Company)TrAIL), FES and its subsidiaries FGCO and NGC, and FESC. AE merged with a subsidiary of FirstEnergy on February 25, 2011, with AE remainingcontinuing 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, the NERC 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, 2010 for FirstEnergy, FES and the Utility Registrants, as applicable, and the Current Report on Form 8-K filed by FirstEnergy on February 25, 2011, as amended on April 19, 2011.applicable. The consolidated unaudited financial statements of FirstEnergy, FES and each of the Utility 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, Variable Interest Entities). Investments in affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but with respect to which are not the primary beneficiary and do not exercise control, follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage share of the entity’s earnings is reported in the Consolidated Statements of Income.
2. MERGER
Merger
On February 25, 2011, the merger between FirstEnergy and Allegheny closed. Pursuant to the terms of the Agreement and Plan of Merger among FirstEnergy, Element Merger Sub, Inc., a Maryland corporation and a wholly-owned subsidiary of FirstEnergy (Merger Sub), and AE, Merger Sub merged with and into AE, with AE continuing as the surviving corporation and becoming a wholly-owned subsidiary of FirstEnergy. As part of the merger, AE shareholders received 0.667 of a share of FirstEnergy common stock for each share of AE common stock outstanding as of the date the merger was completed, and all outstanding AE equity-based employee compensation awards were converted into FirstEnergy equity-based awards on the same basis.
The merger created a combined company with increased scale and scope and greater diversification in energy delivery, generation and transmission. The combined company is the largest U.S. diversified electric utility by customers and operates one of the largest unregulated power generation fleets in the United States with FirstEnergy’s total current capacity of approximately 23,000 MW, which includes approximately 3,000 MW of regulated generation.

26

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 
    

27

The preliminary allocation of the total consideration transferred to the assets acquired and liabilities assumed includes adjustments for the fair value of coal contracts, energy supply contracts, emission allowances, unregulated property, plant and equipment, derivative instruments, goodwill, intangible assets, long-term debt and accumulated deferred income taxes. The preliminary allocation of the purchase price is as follows:
    
 Preliminary 
 Purchase Price     
(In millions) Allocation  
  
Current assets $1,509  $1,494 
Property, plant and equipment 9,656  9,656 
Investments 138  138 
Goodwill 952  881 
Other noncurrent assets 1,262  1,347 
Current liabilities  (714)  (716)
Noncurrent liabilities  (3,453)  (3,452)
Long-term debt and other long-term obligations  (4,996)  (4,994)
      
 $4,354  $4,354 
      
Assumptions and estimates underlyingThe 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 valuevalues 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 are subjectrecorded during the quarter ended March 31, 2011 was not significant. Further modifications to change pending furtherthe 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 $952$881 million washas been assigned entirely to the Competitive Energy Services segment based on expected synergies from the merger. The goodwill is not deductible for tax purposes.
Total goodwill recognized by segment in FirstEnergy’s Consolidated Balance Sheet is as follows:
                                        
 Competitive Regulated      Competitive Regulated     
 Regulated Energy Independent Other/    Regulated Energy Independent Other/   
(In millions) Distribution Services Transmission Corporate Consolidated  Distribution Services Transmission Corporate Consolidated 
  
Balance at December 31, 2010 $5,551 $24 $— $— $5,575 
Balance as of December 31, 2010 $5,551 $24 $— $— $5,575 
  
Merger with Allegheny — 952 — — 952  — 881 — — 881 
                      
  
Balance at March 31, 2011 $5,551 $976 $— $— $6,527 
Balance as of June 30, 2011 $5,551 $905 $— $— $6,456 
                      
   

 

2728

The preliminary valuation of the additional intangible assets and liabilities recorded as result of the merger is as follows:
                
 Preliminary Weighted Average  Preliminary Weighted Average 
(In millions) Valuation Amortization Period  Valuation Amortization Period 
Above market contracts:  
Energy supply contracts $189 10 years
Energy contracts $189 10 years
NUG contracts 124 25 years 124 25 years
Coal supply contracts 525 8 years 516 8 years
      
 838  829 
  
Below market contracts:  
NUG contracts 143 13 years 143 13 years
Coal supply contracts 86 7 years 83 7 years
Transportation contract 35 8 years 35 8 years
      
 264  261 
      
  
Net intangible assets $568 
 $574    
   
The fair value measurements of intangible assets and liabilities were primarily based on significant unobservable inputs and thus represent level 3 measurements as defined in accounting guidance for fair value measurements.
The fair value of Allegheny’s energy, NUG and gas transportation contracts, both above-market and below-market, were estimated based on the present value of the above/below market cash flows attributable to the contracts based on the contract type, discounted by a current market interest rate consistent with the overall credit quality of the portfolio. The above/below market cash flows were estimated by comparing the expected cash flow based on existing contracted prices and expected volumes with the cash flows from estimated current market contract prices for the same expected volumes. The estimated current market contract prices were derived considering current market prices, such as the price of energy and transmission, miscellaneous fees and a normal profit margin. The weighted average amortization period was determined based on the expected volumes to be delivered over the life of the contract.
The fair value of coal supply contracts was determined in a similar manner based on the present value of the above/below market cash flows attributable to the contracts. The fair value ofadjustment for these contracts will beis being amortized based on expected deliveries under each contract.
TotalAs of June 30, 2011, intangible assets recorded on FirstEnergy’s Consolidated Balance Sheet, as of March 31, 2011 are as follows:
     
  Intangible 
(In millions) Assets 
Purchase contract assets    
NUG $241 
OVEC  52 
    
   293 
     
Intangible assets    
Coal contracts  520 
FES customer intangible assets  132 
Energy contracts  130 
    
   782 
    
     
  $1,075 
    
Other intangible assets acquiredincluding those recorded in connection with the Allegheny 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 havingwith a fair value of $126$169 million are included in “Property, plant and equipment” on FirstEnergy’s Consolidated Balance Sheet as of March 31,June 30, 2011.
In connection with the merger, FirstEnergy recorded merger transaction costs of approximately $82$7 million ($685 million net of tax) and $14$7 million ($105 million net of tax) during the three months ended June 30, 2011 and 2010, respectively and approximately $89 million ($72 million net of merger transaction coststax) and $21 million ($15 million net of tax) during the first quartersix months of 2011 and 2010, respectively. These costs are included in “Other operating expenses” in the Consolidated StatementStatements of Income. Merger transaction costs recognized in the first quartersix months of 2011 include $56 million ($47 net of tax) of change in control and other benefit payments to AE executives.

 

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FirstEnergy also recorded approximately $75$10 million ($6 million net of tax) and $85 million ($66 million net of tax) in merger integration costs during the first quarter ofthree 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.
The amounts of revenueRevenues and earnings of Allegheny since the merger date included in FirstEnergy’s Consolidated Statement of Income for the quarter ended March 31,periods subsequent to the February 25, 2011 merger date are as follows:
            
 February 26 -  April 1 – February 26 – 
(In millions, except per share amounts) March 31, 2011  June 30, 2011 June 30, 2011 
  
Total revenues $437  $1,181 $1,618 
Net Income(1)
  (46)
Earnings available to FirstEnergy Corp.(1)
 63 17 
  
Basic Earnings Per Share $(0.13) $0.15 $0.04 
Diluted Earnings Per Share $(0.13) $0.15 $0.04 
   
(1) Includes Allegheny’s after-tax merger costs of $52 million.$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. Approximately $83 million and $27 million of combinedCombined pre-tax transaction costs incurred were incurredapproximately $7 million and $11 million in the three months ended March 31,June 30, 2011 and March 31,2010, respectively, and approximately $90 million and $39 million in the six months ended June 30, 2011 and 2010, respectively. In addition, induring the threesix months ended March 31,June 30, 2011, $75$85 million of pre-tax merger integration costs and $24$32 million of charges from merger settlements approved by regulatory agencies have beenwere 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 had the pro forma events taken place on the dates indicated, or the future consolidated results of operations of the combined company.
                        
 Three Months Ended  Three Months Ended Six Months Ended 
 March 31 
(Pro forma amounts in millions, except per share amounts) 2011 2010 
(Pro forma amounts in millions, except June 30 June 30 
per share amounts) 2011 2010 2011 2010 
  
Revenues $4,786 $4,685  $4,062 $4,401 $8,848 $9,086 
Net income attributable to FirstEnergy $137 $255 
Earnings available to FirstEnergy
 $186 $389 $323 $644 
  
Basic Earnings Per Share $0.33 $0.61  $0.44 $0.93 $0.77 $1.54 
              
Diluted Earnings Per Share $0.33 $0.61  $0.44 $0.93 $0.77 $1.53 
              

 

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3. EARNINGS PER SHARE
Basic earnings per share of common stock are computed using the weighted average of actual common shares outstanding during the relevant 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 would 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 Ended  Three Months Six Months 
Reconciliation of Basic and Diluted March 31 
Earnings per Share of Common Stock 2011 2010 
 (In millions, except per 
Reconciliation of Basic and Diluted Earnings per Share Ended June 30 Ended June 30 
of Common Stock 2011 2010 2011 2010 
 share amounts)  (In millions, except per share amounts) 
  
Earnings available to FirstEnergy Corp. $50 $155  $181 $265 $231 $420 
     
          
Weighted average number of basic shares outstanding(1)
 342 304  418 304 380 304 
Assumed exercise of dilutive stock options and awards 1 2  2 1 2 1 
              
Weighted average number of diluted shares outstanding(1)
 343 306  420 305 382 305 
              
  
Basic earnings per share of common stock $0.15 $0.51  $0.43 $0.87 $0.61 $1.38 
              
Diluted earnings per share of common stock $0.15 $0.51  $0.43 $0.87 $0.61 $1.37 
              
   
(1) Includes 113 million shares issued to AE stockholders for the periodperiods subsequent to the merger date. (See Note 2, Merger)2)
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 March 31,June 30, 2011 and December 31 2010:
                                
 March 31, 2011 December 31, 2010  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(1)
 $18,743 $19,776 $13,928 $14,845  $18,371 $19,436 $13,928 $14,845 
FES 4,099 4,227 4,279 4,403  4,056 4,310 4,279 4,403 
OE 1,159 1,334 1,159 1,321  1,158 1,367 1,159 1,321 
CEI 1,831 2,035 1,853 2,035  1,831 2,083 1,853 2,035 
TE 600 666 600 653  600 690 600 653 
JCP&L 1,802 1,980 1,810 1,962  1,795 2,008 1,810 1,962 
Met-Ed 742 826 742 821  729 828 742 821 
Penelec 1,120 1,190 1,120 1,189  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 March 31,June 30, 2011 of $4,995$4,530 million and $5,004$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 obligations 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 debt with similar characteristics offered by corporations with credit ratings similar to those of FirstEnergy, FES, the Utilities and 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.

30

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 nuclear decommissioning trusts,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 March 31,June 30, 2011 and December 31, 2010:
                                                                
 March 31, 2011(1) December 31, 2010(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 $1,985 $32 $— $2,017 $1,699 $31 $— $1,730  $2,015 $48 $— $2,063 $1,699 $31 $— $1,730 
FES 1,012 18 — 1,030 980 13 — 993  1,023 26 — 1,049 980 13 — 993 
OE 124 1 — 125 123 1 — 124  128 3 — 131 123 1 — 124 
TE 51 — — 51 42 — — 42  52 1 — 53 42 — — 42 
JCP&L 358 7 — 365 281 9 — 290  353 9 — 362 281 9 — 290 
Met-Ed 240 4 — 244 127 4 — 131  249 5 — 254 127 4 — 131 
Penelec 200 2 — 202 145 4 — 149  210 4 — 214 145 4 — 149 
  
Equity securities
  
FirstEnergy $186 $7 $— $193 $268 $69 $— $337  $187 $11 $— $198 $268 $69 $— $337 
FES 88 5 — 93 — — — —  90 6 — 96 — — — — 
TE 24 1 — 25 — — — —  24 2 — 26 — — — — 
JCP&L 21 — — 21 80 17 — 97  21 1 — 22 80 17 — 97 
Met-Ed 33 1 — 34 125 35 — 160  32 1 — 33 125 35 — 160 
Penelec 20 — — 20 63 16 — 79  20 1 — 21 63 16 — 79 
   
(1) Excludes cash investments, receivables, payables, deferred taxes and accrued income: FirstEnergy — $97– $130 million; FES — $37– $39 million; OE — $2 million; TE — $1– $3 million; JCP&L — $12– $19 million; Met-Ed — $27– $14 million and Penelec — $18– $55 million.
 
(2) Excludes cash investments, receivables, payables, deferred taxes and accrued income: FirstEnergy —– $193 million; FES —– $153 million; OE —– $3 million; TE —– $34 million; JCP&L —– $3 million; Met-Ed —– $(3) million and Penelec —– $4 million.

 

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Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales net of adjustments recorded to earnings and interest and dividend income for the three months and six months ended March 31,June 30, 2011 and 2010 were as follows:
                
Three Months Ended June 30,Three Months Ended June 30, 
                
 Interest and  Interest and 
March 31, 2011 Sales Proceeds Realized Gains Realized Losses Dividend Income 
2011 Sales Proceeds Realized Gains Realized Losses Dividend Income 
 (In millions)  (In millions) 
FirstEnergy $970 $100 $(29) $24  $734 $22 $(16) $28 
FES 216 12  (15) 15  297 10  (7) 17 
OE 8 — — 1  12 — — 1 
TE 14 1  (1) 1  15 1  (1) 1 
JCP&L 217 22  (4) 4  159 4  (2) 4 
Met-Ed 336 43  (5) 2  165 4  (3) 3 
Penelec 179 22  (4) 1  86 3  (3) 2 
                                
 Interest and  Interest and 
March 31, 2010 Sales Proceeds Realized Gains Realized Losses Dividend Income 
2010 Sales Proceeds Realized Gains Realized Losses Dividend Income 
 (In millions)  (In millions) 
FirstEnergy $733 $37 $(51) $22  $1,183 $46 $(36) $16 
FES 272 13  (24) 13  685 41  (35) 9 
OE 2 — — 1  57 2 — — 
TE 31 1  (1) 1  76 2 — — 
JCP&L 190 8  (8) 4  91 — — 3 
Met-Ed 144 9  (11) 2  233 1  (1) 2 
Penelec 93 6  (7) 1  41 — — 2 
Unrealized gains applicable to the decommissioning trusts of FES, OE and TE are recognized in OCI because fluctuations in fair value will eventually impact earnings. The decommissioning trusts of JCP&L, Met-Ed and Penelec are subject to regulatory accounting. Net unrealized gains and losses are recorded as regulatory assets or liabilities because the difference between investments held in trust and the decommissioning liabilities will be recovered from or refunded to customers.
                 
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 
The investment policy for the nuclear decommissioning trust funds restricts or limits the plans’ ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, preferred stocks, securities convertible into common stock and securities of the trust fund’s custodian or managers and their parents or subsidiaries.
                 
              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 
FirstEnergy recognized $3 million and $11 million of net realized losses for the three-month period ended March 31, 2011 and 2010, respectively, resulting from the sale of securities held in nuclear decommissioning trusts.
Held-To-Maturity Securities
The following table provides the amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities as of March 31,June 30, 2011 and December 31, 2010:
                                                                
 March 31, 2011 December 31, 2010  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 $422 $79 $— $501 $476 $91 $— $567  $414 $84 $— 498 $476 $91 $— $567 
OE 190 45 — 235 190 51 — 241  178 45 — 223 190 51 — 241 
CEI 287 33 — 320 340 41 — 381  287 39 — 326 340 41 — 381 
Investments in emission allowances, employee benefits and cost and equity method investments totaling $345 million as of March 31,June 30, 2011 and $259 million as of December 31, 2010, are not required to be disclosed and are excluded from the amounts reported above.

 

3233

Notes Receivable
The table below provides the approximate fair value and related carrying amounts of notes receivable as of March 31,June 30, 2011 and December 31, 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.
                                
 March 31, 2011 December 31, 2010  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 $7 $8  $6 $7 $7 $8 
TE 82 94 104 118  82 94 104 118 

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(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 in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 — Pricing inputs are either directly or indirectly observable in the market as of the reporting date, other than quoted prices in active markets included in Level 1. Additionally, Level 2 includes those financial instruments that are valued using models or other valuation methodologies based on assumptions that are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Instruments in this category may include non-exchange-traded derivatives such as forwards and certain interest rate swaps.
Level 3 — Pricing inputs include inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. FirstEnergy develops its view of the future market price of key commodities through a combination of market observation and assessment (generally for the short term) and fundamental modeling (generally for the long term). Key fundamental electricity model inputs are generally directly observable in the market or derived from publicly available historic and forecast data. Some key inputs reflect forecasts published by industry leading consultants who generally employ similar fundamental modeling approaches. Fundamental model inputs and results, as well as the selection of consultants, reflect the consensus of appropriate FirstEnergy management. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs.
FirstEnergy utilizes market data and assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs.
The determination of the fair value measures takes into consideration various factors. These factors include nonperformance risk, including counterparty credit risk and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of nonperformance risk was immaterial in the fair value measurements.
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 liabilities that are accounted formeasured at fair value on a recurring basis by level within the fair value hierarchy as of March 31, 2011 and December 31, 2010. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. FirstEnergy’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the fair valuation of assets and liabilities and their placement within the fair value hierarchy levels. The fair value of financial assets and liabilities as of March 31, 2011 assumed in the merger with Allegheny totaled $52 million and $51 million, respectively.hierarchy. There were no significant transfers between Level 1, Level 2levels during the three months and Level 3 as of March 31, 2011 and December 31, 2010.six months ended June 30, 2011.

 

3335

FirstEnergy Corp.
The following tables summarize assets and liabilities recorded on FirstEnergy’s Consolidated Balance Sheets at fair value as of March��31,June 30, 2011 and December 31, 2010:
                                
March 31, 2011 Level 1 Level 2 Level 3 Total 
June 30, 2011 Level 1 Level 2 Level 3 Total 
 (In millions)  (In millions) 
Assets
  
Corporate debt securities $— $877 $— $877  $— $868 $— $868 
Derivative assets — commodity contracts — 524 — 524  — 312 — 312 
Derivative assets — FTRs — — 1 1  — — 13 13 
Derivative assets — interest rate swaps — 4 — 4  — 4 — 4 
Derivative assets — NUG contracts(1)
 — — 117 117  — — 75 75 
Equity securities(2)
 194 — — 194  198 — — 198 
Foreign government debt securities — 150 — 150  — 206 — 206 
U.S. government debt securities — 681 — 681  — 673 — 673 
U.S. state debt securities — 297 — 297  — 306 — 306 
         
Other(4)
 — 148 — 148  — 146 — 146 
                  
Total assets
 $194 $2,681 $118 $2,993  $198 $2,515 $88 $2,801 
                  
  
Liabilities
  
Derivative liabilities — commodity contracts $— $(583) $— $(583) $— $(362) $— $(362)
Derivative liabilities — FTRs — —  (12)  (12) — —  (7)  (7)
Derivative liabilities — interest rate swaps —  (5) —  (5) —  (5) —  (5)
         
Derivative liabilities — NUG contracts(1)
 — —  (478)  (478) — —  (522)  (522)
                  
Total liabilities
 $— $(588) $(490) $(1,078) $— $(367) $(529) $(896)
                  
 
Net assets (liabilities)(3)
 $194 $2,093 $(372) $1,915  $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 the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.
 
(3) Excludes $(31)$6 million and $(7) million as of March 31,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.
 
(4) Primarily consists of cash and cash equivalents.

 

3436

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 forduring the periods ending March 31,June 30, 2011 and December 31, 2010, respectively:2010:
                        
 Derivative Asset(1) Derivative Liability(1)              Net(1)                Derivative Asset(1) Derivative Liability(1) Net(1) 
 (In millions)  (In millions) 
January 1, 2011 Balance $122 $(466) $(344) $122 $(466) $(344)
Realized gain (loss) — — —  — — — 
Unrealized gain (loss)  (1)  (89)  (90)  (40)  (203)  (243)
Purchases — — —  13  (3) 10 
Issuances — — —  — — — 
Sales — — —  — — — 
Settlements  (3) 77 74   (6) 154 148 
Transfers in (out) of Level 3 —  (12)  (12)
Transfers into Level 3 —  (12)  (12)
              
March 31, 2011 Balance $118 $(490) $(372)
June 30, 2011 Balance $89 $(530) $(441)
              
  
January 1, 2010 Balance $200 $(643) $(443) $200 $(643) $(443)
Realized gain (loss) — — —  — — — 
Unrealized gain (loss)  (71)  (110)  (181)  (71)  (110)  (181)
Purchases — — —  — — — 
Issuances — — —  — — — 
Sales — — —  — — — 
Settlements  (7) 287 280   (7) 287 280 
Transfers in (out) of Level 3 — — — 
Transfers into Level 3 — — — 
              
December 31, 2010 Balance $122 $(466) $(344) $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 March 31,June 30, 2011 and December 31, 2010:
                 
March 31, 2011 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
Corporate debt securities $—  $567  $—  $567 
Derivative assets — commodity contracts  —   476   —   476 
Derivative assets — FTRs  —   —   1   1 
Equity securities(3)
  93   —   —   93 
Foreign government debt securities  —   148   —   148 
U.S. government debt securities  —   304   —   304 
             
U.S. state debt securities  —   8   —   8 
Other(2)
  —   43   —   43 
             
Total assets
 $93  $1,546  $1  $1,640 
             
                 
Liabilities
                
Derivative liabilities — commodity contracts $—  $(549) $—  $(549)
             
Total liabilities
 $—  $(549) $—  $(549)
             
                 
Net assets (liabilities)(1)
 $93  $997  $1  $1,091 
             

35

                                
December 31, 2010 Level 1 Level 2 Level 3 Total 
June 30, 2011 Level 1 Level 2 Level 3 Total 
 (In millions)  (In millions) 
Assets
  
Corporate debt securities $— $528 $— $528  $— $562 $— $562 
Derivative assets — commodity contracts — 241 — 241  — 283 — 283 
Derivative assets — FTRs — — 2 2 
Equity securities(3)
 96 — — 96 
Foreign government debt securities — 147 — 147  — 160 — 160 
U.S. government debt securities — 308 — 308  — 316 — 316 
U.S. state debt securities — 6 — 6  — 7 — 7 
Other(2)
 — 148 — 148  — 42 — 42 
                  
Total assets
 $— $1,378 $— $1,378  $96 $1,370 $2 $1,468 
                  
  
Liabilities
  
Derivative liabilities – commodity contracts $— $(348) $— $(348)
Derivative liabilities — commodity contracts $— $(327) $— $(327)
                  
Total liabilities
 $— $(348) $— $(348) $— $(327) $— $(327)
                  
  
Net assets (liabilities)(1)
 $— $1,030 $— $1,030  $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 $(3) million and $7 million as of MarchDecember 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.
Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the fair value of FTRs held by FES and classified as Level 3 in the fair value hierarchy for the period ending March 31, 2011:
             
  Derivative Asset  Derivative Liability  Net 
  FTRs  FTRs             FTRs            
  (In millions) 
January 1, 2011 Balance $—  $—  $— 
Realized gain (loss)  —   —   — 
Unrealized gain (loss)  1   —   1 
Purchases  —   —   — 
Issuances  —   —   — 
Sales  —   —   — 
Settlements  —   —   — 
Transfers in (out) of Level 3  —   —   — 
          
March 31, 2011 Balance $1  $—  $1 
          
Ohio Edison Company
The following tables summarize assets and liabilities recorded on OE’s Consolidated Balance Sheets at fair value as of March 31, 2011 and December 31, 2010:
                 
March 31, 2011 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
U.S. government debt securities $—  $125  $—  $125 
Other  —   6   —   6 
             
Total assets(1)
 $—  $131  $—  $131 
             
                 
December 31, 2010 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
U.S. government debt securities $—  $124  $—  $124 
Other  —   2   —   2 
             
Total assets(1)
 $—  $126  $—  $126 
             
(1)Excludes $(3) million and $1 million as of March 31, 2011 and December 31, 2010 of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table.

 

3639

Toledo Edison Company
The following tables summarize assets and liabilities recorded on TE’s Consolidated Balance Sheets at fair value as of March 31, 2011 and December 31, 2010:
                 
March 31, 2011 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
Corporate debt securities $—  $16  $—  $16 
Equity securities(3)
  25   —   —   25 
U.S. government debt securities  —   32   —   32 
U.S. state debt securities  —   2   —   2 
Other(2)
  —   3   —   3 
             
Total assets(1)
 $25  $53  $—  $78 
             
                 
December 31, 2010 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
Corporate debt securities $—  $7  $—  $7 
U.S. government debt securities  —   33   —   33 
U.S. state debt securities  —   1   —   1 
Other(2)
  —   35   —   35 
             
Total assets(1)
 $—  $76  $—  $76 
             
(1)Excludes $(1) million and $2 million as of March 31, 2011 and December 31, 2010 of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table.
(2)Primarily consists of cash and cash equivalents.
(3)NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.
Jersey Central Power & Light Company
The following tables summarize assets and liabilities recorded on JCP&L’s Consolidated Balance Sheets at fair value as of March 31,June 30, 2011 and December 31, 2010:
                 
March 31, 2011 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
Corporate debt securities $—  $92  $—  $92 
Derivative assets — commodity contracts  —   —   —   — 
Derivative assets — NUG contracts(1)
  —   —   6   6 
Equity securities(2)
  21   —   —   21 
Foreign government debt securities  —   1   —   1 
U.S. government debt securities  —   60   —   60 
U.S. state debt securities  —   214   —   214 
             
Other  —   16   —   16 
             
Total assets
 $21  $383  $6  $410 
             
                 
Liabilities
                
Derivative liabilities – NUG contracts(1)
 $—  $—  $(239) $(239)
             
Total liabilities
 $—  $—  $(239) $(239)
             
                 
Net assets (liabilities)(3)
 $21  $383  $(233) $171 
             

37

                                
December 31, 2010 Level 1 Level 2 Level 3 Total 
June 30, 2011 Level 1 Level 2 Level 3 Total 
 (In millions)  (In millions) 
Assets
  
Corporate debt securities $— $23 $— $23  $— $81 $— $81 
Derivative assets — commodity contracts — 2 — 2 
Derivative assets — NUG contracts(1)
 — — 6 6  — — 5 5 
Equity securities(2)
 96 — — 96  21 — — 21 
Foreign government debt securities — 13 — 13 
U.S. government debt securities — 33 — 33  — 54 — 54 
U.S. state debt securities — 236 — 236  — 215 — 215 
Other — 4 — 4  — 14 — 14 
                  
Total assets
 $96 $298 $6 $400  $21 $377 $5 $403 
                  
  
Liabilities
  
Derivative liabilities – NUG contracts(1)
 $— $— $(233) $(233)
Derivative liabilities — NUG contracts(1)
 $— $— $(240) $(240)
                  
Total liabilities
 $— $— $(233) $(233) $— $— $(240) $(240)
                  
  
Net assets (liabilities)(3)
 $96 $298 $(227) $167  $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.
 
(2) NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.
 
(3) Excludes $(8)$5 million and $(3) million as of March 31,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.

40

Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the fair value of NUG contracts held by JCP&L and classified as Level 3 in the fair value hierarchy forduring the periods ending March 31,June 30, 2011 and December 31, 2010:
                        
 Derivative Asset Derivative Liability Net  Derivative Asset Derivative Liability Net 
 NUG Contracts(1) NUG Contracts(1) NUG Contracts(1)  NUG Contracts(1) NUG Contracts(1) NUG Contracts(1) 
 (In millions)  (In millions) 
January 1, 2011 Balance $6 $(233) $(227) $6 $(233) $(227)
Realized gain (loss) — — —  — — — 
Unrealized gain (loss) —  (42)  (42)  (1)  (71)  (72)
Purchases — — —  — — — 
Issuances — — —  — — — 
Sales — — —  — — — 
Settlements — 36 36  — 64 64 
Transfers in (out) of Level 3 — — —  — — — 
              
March 31, 2011 Balance $6 $(239) $(233)
June 30, 2011 Balance $5 $(240) $(235)
              
  
January 1, 2010 Balance $8 $(399) $(391) $8 $(399) $(391)
Realized gain (loss) — — —  — — — 
Unrealized gain (loss)  (1) 36 35   (1) 36 35 
Purchases — — ���  — — — 
Issuances — — —  — — — 
Sales — — —  — — — 
Settlements  (1) 130 129   (1) 130 129 
Transfers in (out) of Level 3 — — —  — — — 
              
December 31, 2010 Balance $6 $(233) $(227) $6 $(233) $(227)
              
(1) Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings.

 

3841

Metropolitan Edison Company
The following tables summarize assets and liabilities recorded on Met-Ed’s Consolidated Balance Sheets at fair value as of March 31,June 30, 2011 and December 31, 2010:
                                
March 31, 2011 Level 1 Level 2 Level 3 Total 
June 30, 2011 Level 1 Level 2 Level 3 Total 
 (In millions)  (In millions) 
Assets
  
Corporate debt securities $— $131 $— $131  $— $138 $— $138 
Derivative assets — commodity contracts — — — — 
Derivative assets — NUG contracts(1)
 — — 107 107  — — 66 66 
Equity securities(2)
 34 — — 34  33 — — 33 
Foreign government debt securities — 2 — 2  — 20 — 20 
U.S. government debt securities — 100 — 100  — 87 — 87 
U.S. state debt securities — 2 — 2  — 2 — 2 
Other — 37 — 37  — 22 — 22 
                  
Total assets
 $34 $272 $107 $413  $33 $269 $66 $368 
                  
  
Liabilities
  
Derivative liabilities – NUG contracts(1)
 $— $— $(118) $(118)
Derivative liabilities — NUG contracts(1)
 $— $— $(122) $(122)
                  
Total liabilities
 $— $— $(118) $(118) $— $— $(122) $(122)
                  
 
Net assets (liabilities)(3)
 $34 $272 $(11) $295  $33 $269 $(56) $246 
                  
                                
December 31, 2010 Level 1 Level 2 Level 3 Total  Level 1 Level 2 Level 3 Total 
 (In millions)  (In millions) 
Assets
  
Corporate debt securities $— $32 $— $32  $— $32 $— $32 
Derivative assets — commodity contracts — 5 — 5  — 5 — 5 
Derivative assets — NUG contracts(1)
 — — 112 112  — — 112 112 
Equity securities(2)
 160 — — 160  160 — — 160 
Foreign government debt securities — 1 — 1  — 1 — 1 
U.S. government debt securities — 88 — 88  — 88 — 88 
U.S. state debt securities — 2 — 2  — 2 — 2 
Other — 14 — 14  — 14 — 14 
                  
Total assets
 $160 $142 $112 $414  $160 $142 $112 $414 
                  
  
Liabilities
  
Derivative liabilities – NUG contracts(1)
 $— $— $(116) $(116)
Derivative liabilities — NUG contracts(1)
 $— $— $(116) $(116)
                  
Total liabilities
 $— $— $(116) $(116) $— $— $(116) $(116)
                  
  
Net assets (liabilities)(3)
 $160 $142 $(4) $298  $160 $142 $(4) $298 
                  
(1) NUG contracts are subject to regulatory accounting and do not impact earnings.
 
(2) NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.
 
(3) Excludes $(1) million and $(9) million as of March 31,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.

 

3942

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 forduring the periods ending March 31,June 30, 2011 and December 31, 2010:
                        
 Derivative Asset Derivative Liability Net  Derivative Asset Derivative Liability Net 
 NUG Contracts(1) NUG Contracts(1) NUG Contracts(1)  NUG Contracts(1) NUG Contracts(1) NUG Contracts(1) 
 (In millions)  (In millions) 
January 1, 2011 Balance $112 $(116) $(4) $112 $(116) $(4)
Realized gain (loss) — — —  — — — 
Unrealized gain (loss)  (2)  (16)  (18)  (42)  (36)  (78)
Purchases — — —  — — — 
Issuances — — —  — — — 
Sales — — —  — — — 
Settlements  (3) 14 11   (4) 30 26 
Transfers in (out) of Level 3 — — —  — — — 
              
March 31, 2011 Balance $107 $(118) $(11)
June 30, 2011 Balance $66 $(122) $(56)
              
  
January 1, 2010 Balance $176 $(143) $33  $176 $(143) $33 
Realized gain (loss) — — —  — — — 
Unrealized gain (loss)  (59)  (38)  (97)  (59)  (38)  (97)
Purchases — — —  — — — 
Issuances — — —  — — — 
Sales — — —  — — — 
Settlements  (5) 65 60   (5) 65 60 
Transfers in (out) of Level 3 — — —  — — — 
              
December 31, 2010 Balance $112 $(116) $(4) $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 March 31,June 30, 2011 and December 31, 2010:
                 
March 31, 2011 Level 1  Level 2  Level 3  Total 
  (In millions) 
Assets
                
Corporate debt securities $—  $70  $—  $70 
Derivative assets — commodity contracts  —   —   —   — 
Derivative assets — NUG contracts(1)
  —   —   4   4 
Equity securities(2)
  20   —   —   20 
Foreign government debt securities  —   —   —   — 
U.S. government debt securities  —   60   —   60 
U.S. state debt securities  —   72   —   72 
             
Other  —   32   —   32 
             
Total assets
 $20  $234  $4  $258 
             
                 
Liabilities
                
Derivative liabilities – NUG contracts(1)
 $—  $—  $(122) $(122)
             
Total liabilities
 $—  $—  $(122) $(122)
             
                 
Net assets (liabilities)(3)
 $20  $234  $(118) $136 
             

40

                                
December 31, 2010 Level 1 Level 2 Level 3 Total 
June 30, 2011 Level 1 Level 2 Level 3 Total 
 (In millions)  (In millions) 
Assets
  
Corporate debt securities $— $8 $— $8  $— $69 $— $69 
Derivative assets — commodity contracts — 2 — 2 
Derivative assets — NUG contracts(1)
 — — 4 4  — — 4 4 
Equity securities(2)
 81 — — 81  20 — — 20 
Foreign government debt securities 12 12 
U.S. government debt securities — 9 — 9  — 52 — 52 
U.S. state debt securities — 133 — 133  — 81 — 81 
Other — 5 — 5  — 53 — 53 
                  
Total assets
 $81 $157 $4 $242  $20 $267 $4 $291 
                  
  
Liabilities
  
Derivative liabilities – NUG contracts(1)
 $— $— $(117) $(117)
Derivative liabilities — NUG contracts(1)
 $— $— $(160) $(160)
                  
Total liabilities
 $— $— $(117) $(117) $— $— $(160) $(160)
                  
  
Net assets (liabilities)(3)
 $81 $157 $(113) $125  $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 $(15)$1 million and $(3) million as of March 31,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 forduring the periods ended March 31,June 30, 2011 and December 31, 2010:
                        
 Derivative Asset Derivative Liability Net  Derivative Asset Derivative Liability Net 
 NUG Contracts(1) NUG Contracts(1) NUG Contracts(1)  NUG Contracts(1) NUG Contracts(1) NUG Contracts(1) 
 (In millions)  (In millions) 
January 1, 2011 Balance $4 $(117) $(113) $4 $(117) $(113)
Realized gain (loss) — — —  — — — 
Unrealized gain (loss) —  (30)  (30) —  (88)  (88)
Purchases — — —  — — — 
Issuances — — —  — — — 
Sales — — —  — — — 
Settlements — 25 25  — 45 45 
Transfers in (out) of Level 3 — — —  — — — 
              
March 31, 2011 Balance $4 $(122) $(118)
June 30, 2011 Balance $4 $(160) $(156)
              
  
January 1, 2010 Balance $16 $(101) $(85) $16 $(101) $(85)
Realized gain (loss) — — —  — — — 
Unrealized gain (loss)  (11)  (108)  (119)  (11)  (108)  (119)
Purchases — — —  — — — 
Issuances — — —  — — — 
Sales — — —  — — — 
Settlements  (1) 92 91   (1) 92 91 
Transfers in (out) of Level 3 — — —  — — — 
              
December 31, 2010 Balance $4 $(117) $(113) $4 $(117) $(113)
              
(1) Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings.

41

5. DERIVATIVE INSTRUMENTS
FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. To manage the volatility relating to these exposures, FirstEnergy established aFirstEnergy’s Risk Policy Committee, comprised of members of senior management, which provides general management oversight for risk management activities throughout FirstEnergy. The Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management 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 under the accrual method of accounting, and their effects are included in earnings at the time of contract performance. Changes in the fair value of derivative instruments that qualify and are designated as cash flow hedge instruments are recorded toin AOCL. ChangeChanges in the fair value of derivative instruments that are not designated as cash flow hedge instruments are recorded in thenet income statement on a mark-to-market basis. FirstEnergy’sFirstEnergy 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 lossesgains included in AOCL associated with dedesignated cash flow hedges totaled $6$8 million as of March 31,June 30, 2011. Since the forecasted transactions remain probable of occurring, these amounts were “frozen” in AOCL and will be amortized into earnings over the life of the hedging instruments. Reclassifications from AOCL into other operating expenseexpenses totaled $5$14 million forand $19 million during the three-monthsthree months and six months ended March 31, 2011.June 30, 2011, respectively. Approximately $16$3 million willis expected to be amortized to earnings as expense during the next twelve months.
FirstEnergy has used forward starting swap agreements to hedge a portion of the consolidated interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives were treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. As of March 31,June 30, 2011, no forward starting swap agreements were outstanding. Total unamortized losses included in AOCL associated with prior interest rate cash flow hedges totaled $87$84 million ($5755 million net of tax) as of March 31,June 30, 2011. Based on current estimates, approximately $10 million will be amortized to interest expense during the next twelve months. Reclassifications from AOCL into interest expense totaled $3 million forduring the three-monthsthree months ended March 31,June 30, 2011 and 2010 and $6 million during the six months ended June 30, 2011 and 2010.

45

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 derivative instruments were treated as fair value hedges of fixed-rate, long-term debt issues, protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. As of March 31,June 30, 2011, no fixed-for-floating interest rate swap agreements were outstanding.
As of March 31, 2010, FirstEnergy held fixed-for-floating interest rate swap agreements with combined notional amounts of $950 million. The gains included in interest expense related to interest rate swaps totaled $1 million and the fair value of the derivative instruments totaled $(3) million. There was no impact on the results of operations as a result of ineffectiveness from fair value hedges.
Total unamortizedUnamortized gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements totaled $118$113 million ($7773 million net of tax) as of March 31,June 30, 2011. Based on current estimates, approximately $22 million will be amortized to interest expense during the next twelve months. Reclassifications from long-term debt into interest expense totaled approximately $5$6 million and $1$2 million forduring the three-monthsthree months ended March 31,June 30, 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.

42

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,gas; primarily natural gas is used in FirstEnergy’s peaking units. Heating oil futures are entered into based on expected consumption of oil and the financial risk in FirstEnergy’s coal transportation contracts. Interest rate swaps include two interest rate swap agreements that expire during 2011 with an aggregate notional value of $200 million that were entered into during 2003 to substantially offset two existing interest rate swaps with the same counterparty. The 2003 agreements effectively locked in a net liability and substantially eliminated future income volatility from the interest rate swap positions but do not qualify for cash flow hedge accounting. Derivative instruments are not used in quantities greater than forecasted needs.
As of March 31,June 30, 2011, FirstEnergy’s net liability position under commodity derivative contracts was $59$45 million, which primarily related to FES positions. Under these commodity derivative contracts, FES posted $120$81 million and Allegheny posted $1$2 million in collateral. Certain commodity derivative contracts include credit risk related contingent features that would require FES to post $24$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 March 31,June 30, 2011, an adverse 10% change in commodity prices would decrease net income by approximately $12$31 million ($720 million net of tax) during the next twelve months.
FTRs
FirstEnergy holds FTRs that generally represent an economic hedge of future congestion charges that will be incurred in connection with FirstEnergy’s load obligations. These future obligations are reflected on the Consolidated Balance Sheets; and have not been designated as cash flow hedge instruments. FirstEnergy acquires the majority of its FTRs in an annual auction through a self-scheduling process involving the use of auction revenue rightsARRs allocated to members of an RTO that have load serving obligations.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 FTR auction price less the obligation due to the RTO, and subsequently adjusts the carrying value of remaining FTRs to their estimated fair value at the end of each accounting period prior to settlement. Changes in the fair value of FTRs held by FirstEnergy’s unregulated subsidiaries are included in other operating expenses as unrealized gains or losses. Unrealized gains or losses on FTRs held by FirstEnergy’s regulated subsidiaries are recorded as regulatory assets or liabilities. 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 March 31,June 30, 2011:
                
Derivative AssetsDerivative Assets Derivative Assets 
 Fair Value  Fair Value 
 March 31, December 31,  June 30, December 31, 
 2011 2010  2011 2010 
 (In millions)  (In millions) 
  
Power Contracts  
Current Assets $332 $151  $210 $96 
Noncurrent Assets 192 89  102 40 
FTRs  
Current Assets 1 —  13 — 
Noncurrent Assets — —  — — 
NUGs  
Current Assets 3 3  4 3 
Noncurrent Assets 114 119  71 119 
Interest Rate Swaps  
Current Assets 4 —  4 — 
Noncurrent Assets — —  — — 
Other  
Current Assets — 10  — 10 
Noncurrent Assets — —  — — 
          
Total Derivatives $646 $372  $404 $268 
          
                
Derivative LiabilitiesDerivative Liabilities Derivative Liabilities 
 Fair Value  Fair Value 
 March 31, December 31,  June 30, December 31, 
 2011 2010  2011 2010 
 (In millions)  (In millions) 
  
Power Contracts  
Current Liabilities $408 $266  $274 $209 
Noncurrent Liabilities 175 81  88 38 
FTRs  
Current Liabilities 12 —  7 — 
Noncurrent Liabilities — —  — — 
NUGs  
Current Liabilities 277 229  317 229 
Noncurrent Liabilities 202 238  205 238 
Interest Rate Swaps  
Current Liabilities 5 —  5 — 
Noncurrent Liabilities — —  — — 
Other  
Current Liabilities — —  — — 
Noncurrent Liabilities — —  — — 
          
Total Derivatives $1,079 $814  $896 $714 
          

43

The following table summarizes the volume ofvolumes associated with FirstEnergy’s outstanding derivative transactions as of March 31,June 30, 2011:
                              
 Purchases Sales Net Units Purchases Sales Net Units
 (In thousands)  (In thousands)
Power Contracts 83,603  (100,407)  (16,804) MWH 45,573  (59,549)  (13,976) MWH
FTRs 18,199  (130) 18,069 MWH 53,656 — 53,656 MWH
Interest Rate Swaps 200,000  (200,000) — notional dollars 200,000  (200,000) — notional dollars
NUGs 29,824 — 29,824 MWH 26,903 — 26,903 MWH

47

The effect of derivative instruments on the consolidated statementsConsolidated Statements of income forIncome during the three months and six months ended March 31,June 30, 2011 and 2010, are summarized in the following tables:
                      
 Three Months Ended March 31,  Three Months Ended June 30, 
 Power Interest      Power Interest     
 Contracts FTRs Rate Swaps Other Total  Contracts FTRs Rate Swaps Other Total 
 (In millions)  (In millions) 
Derivatives in a Hedging Relationship
  
2011
  
Gain (Loss) Recognized in AOCL (Effective Portion) $(9) $— $— — $(9) $14 $— $— $— $14 
Effective Gain (Loss) Reclassified to:(1)
  
Purchase Power Expense 14 — — — 14  — — — — — 
Wholesale Revenue  (3) — — —  (3)
Revenues — — — — — 
  
2010
  
Gain (Loss) Recognized in AOCL (Effective Portion) $(2) — — 3 $1  $— $— $— $3 $3 
Effective Gain (Loss) Reclassified to:(1)
  
Purchase Power Expense 2 — — — 2   (3) — — —  (3)
Revenues  (5) — — —  (5)
Fuel Expense — — — 4 4  — — —  (4)  (4)
 
Derivatives Not in a Hedging Relationship
 
2011
 
Unrealized Gain (Loss) Recognized in: 
Purchase Power Expense $29 — — — $29 
Wholesale Revenue — — — — — 
Other Operating Expense  (20) 1 — —  (19)
Realized Gain (Loss) Reclassified to: 
Purchase Power Expense  (19)  (2) — —  (21)
Wholesale Revenue  (2) —  (1) —  (3)
 
2010
 
Unrealized Gain (Loss) Recognized in: 
Purchase Power Expense $(27) — — — $(27)
Realized Gain (Loss) Reclassified to: 
Purchase Power Expense  (25) — — —  (25)
                     
                     
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)

 

4448

             
Derivatives Not in a Hedging Three Months Ended March 31, 
Relationship with Regulatory Offset(2) NUGs  Other  Total 
  (In millions) 
2011
            
Unrealized Loss to NUG Liability: $(89) $—  $(89)
Unrealized Gain to Regulatory Assets:  89   —   89 
             
Realized Gain to NUG Liability:  72   —   72 
Realized Loss to Regulatory Assets:  (72)  —   (72)
Realized Loss to Deferred Charges  —   (10)  (10)
Realized Gain to Regulatory Assets:  —   10   10 
             
2010
            
Unrealized Loss to NUG Liability: $(224)  —  $(224)
Unrealized Gain to Regulatory Assets:  224   —   224 
 
Realized Gain to NUG Liability:  78   —   78 
Realized Loss to Regulatory Assets:  (78)  —   (78)
Realized Loss to Deferred Charges  —   (9)  (9)
Realized Gain to Regulatory Assets:  —   9   9 
                     
  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.
 
(2) Changes in the fair value of certain contracts are deferred for future recovery from (or refund to) customers.

49

The following table provides a reconciliation of changes in the fair value of certain contracts that are deferred for future recoverrecovery from (or refund to) customers.customers during the three months and six months ended June 30, 2011 and 2010:
                        
 Three Months Ended March 31,  Three Months Ended June 30, 
Derivatives Not in a Hedging Relationship with Regulatory Offset(1) NUGs Other Total  NUGs Other Total 
 (In millions)  (In millions) 
Outstanding net asset (liability) as of January 1, 2011 $(345) $10 $(335)
Outstanding net asset (liability) as of April 1, 2011 $(362) $— $(362)
Additions/Change in value of existing contracts  (89) —  (89)  (147) 2  (145)
Settled contracts 72  (10) 62  62 — 62 
              
Outstanding net asset (liability) as of March 31, 2011 $(362) $— $(362)
Outstanding net asset (liability) as of June 30, 2011 $(447) $2 $(445)
              
  
Outstanding net asset (liability) as of January 1, 2010 $(444) $19 $(425)
Outstanding net asset (liability) as of April 1, 2010 $(590) $10 $(580)
Additions/Change in value of existing contracts  (224) —  (224)  (35) —  (35)
Settled contracts 78  (9) 69  68 — 68 
              
Outstanding net asset (liability) as of March 31, 2010 $(590) $10 $(580)
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.

45

FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. During the first quarter ofthree months and six months ended June 30, 2011, FirstEnergy made a $157 million contributionpre-tax contributions to its qualified pension plans.plans of $105 million and $262 million, respectively. FirstEnergy intends to make additional contributions of $220$116 million and $6$2 million to its qualified pension plans and postretirement benefit plans, respectively, in the last threetwo quarters of 2011.

50

As result of the merger with Allegheny, FirstEnergy assumed certain pension and OPEB plans. FirstEnergy measured the funded status of the Allegheny pension plans and postretirement benefit plans other than pensions as of the merger closing date using discount rates of 5.50% and 5.25%, respectively. As a result of the fair value measurement, FirstEnergy recorded accumulated benefit obligation reductions to the Allegheny pension plans and postretirement benefits other than pensions in the amount of $6 million and $2 million, respectively. The expected returns on plan assets used to calculate net period costs for the month ended March 31, 2011 was 8.25% for the Allegheny qualified pension plan and 5.00% for the Allegheny postretirement benefit plans other than pension plans.
The fair values of plan assets for Allegheny’s pension plans and postretirement benefit plans other than pensions at the date of the merger were $954 million and $75 million, respectively, and the actuarially determined benefit obligations for such plans atas of that date were $1,341 million and $272 million, respectively. The expected returns on plan assets used to calculate net periodic costs for periods in 2011 subsequent to the date of the merger are 8.25% for Allegheny’s qualified pension plan and 5.00% for Allegheny’s postretirement benefit plans other than pensions.
FirstEnergy’sThe components of the consolidated net periodic cost for pension and OPEB expenses for the three months ended March 31, 2011 and 2010 were $28 million and $24 million, respectively. The components of FirstEnergy’s net pension and OPEBbenefits (including amounts capitalized) for the three months ended March 30, 2011 and 2010, consisted of the following:were as follows:
                        
 Three Months Ended  Three Months Ended Six Months Ended 
 March 31  June 30 June 30 
Pension Benefit Cost (Credit) 2011 2010  2011 2010 2011 2010 
 (In millions)  (In millions) 
Service cost $29 $25  $34 $25 $62 $49 
Interest cost 84 78  97 79 181 157 
Expected return on plan assets  (102)  (90)  (115)  (90)  (216)  (181)
Amortization of prior service cost 4 3  4 3 7 6 
Recognized net actuarial loss 49 47  48 47 97 94 
Curtailments (1)
  (2) —  — —  (2) — 
Special termination benefits (1)
 9 —  — — 9 — 
              
Net periodic cost $71 $63  $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  Three Months Ended Six Months Ended 
 March 31  June 30 June 30 
Other Postretirement Benefit Cost (Credit) 2011 2010  2011 2010 2011 2010 
 (In millions)  (In millions) 
Service cost $3 $2  $3 $3 $7 $5 
Interest cost 11 11  12 11 23 22 
Expected return on plan assets  (10)  (9)  (10)  (9)  (20)  (18)
Amortization of prior service cost  (48)  (48)  (52)  (48)  (100)  (96)
Recognized net actuarial loss 14 15  14 15 28 30 
              
Net periodic cost $(30) $(29)
Net periodic cost (credit) $(33) $(28) $(62) $(57)
              

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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 months ended March 31, 2011 and 2010 were as follows:
                        
 Three Months Ended  Three Months Ended Six Months Ended 
 March 31  June 30 June 30 
Pension Benefit Cost (Credit) 2011 2010 
Pension Benefit Cost 2011 2010 2011 2010 
 (In millions)  (In millions) 
FES $22 $22  $22 $22 $43 $44 
OE 5 6  5 6 11 11 
CEI 5 5  5 5 10 11 
TE 1 2  2 2 3 4 
JCP&L 5 6  5 6 11 12 
Met-Ed 3 2  3 3 5 5 
Penelec 5 5  4 5 9 9 
Other FirstEnergy Subsidiaries 25 15  22 15 46 29 
              
 $71 $63  $68 $64 $138 $125 
              

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  Three Months Ended  Six Months Ended 
  June 30  June 30 
Other Postretirement Benefit Credit 2011  2010  2011  2010 
  (In millions) 
FES $(8) $(7) $(14) $(13)
OE  (5)  (6)  (12)  (12)
CEI  (2)  (1)  (3)  (3)
TE  —   —   (1)  (1)
JCP&L  (2)  (2)  (3)  (4)
Met-Ed  (2)  (2)  (5)  (4)
Penelec  (2)  (2)  (5)  (4)
Other FirstEnergy Subsidiaries  (12)  (8)  (19)  (16)
             
  $(33) $(28) $(62) $(57)
             
         
  Three Months Ended 
  March 31 
Other Postretirement Benefit Cost (Credit) 2011  2010 
  (In millions) 
FES $(6) $(7)
OE  (6)  (6)
CEI  (2)  (1)
TE  —   (1)
JCP&L  (2)  (2)
Met-Ed  (3)  (2)
Penelec  (3)  (2)
Other FirstEnergy Subsidiaries  (8)  (8)
       
  $(30) $(29)
       
7. VARIABLE INTEREST ENTITIES
FirstEnergy and its subsidiaries perform qualitative analyses to determine whether a variable interest gives FirstEnergy or its subsidiaries a controlling financial interest in a VIE. This analysis identifies the primary beneficiary of a VIE as the enterprise that has both the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.
VIE’sVIEs included in FirstEnergy’s consolidated financial statements are: FEV’s joint venture in the Signal Peak mining and coal transportation operations; the PNBV and Shippingport bond trusts that were created to refinance debt originally issued in connection with sale and leaseback transactions; and wholly owned limited liability companies of JCP&L created to sell transition bonds to securitize the recovery of JCP&L’s bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station, of which $302$295 million was outstanding as of March 31,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 sheetsConsolidated Balance Sheets is primarily the result of net losses of the noncontrolling interests ($515 million) and distributions to owners ($34 million) forduring the threesix months ended March 31,June 30, 2011.
In order to evaluate contracts for consolidation treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregated variable interests into the following categories based on similar risk characteristics and significance as follows:significance.

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PATH-WV
PATH, LLC was formed to construct, through its operating companies, a portion of the PATH Project, which is a high-voltage transmission line that iswas proposed to extend from West Virginia through Virginia and into Maryland, including modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland as directed by PJM. PATH, LLC is a series limited liability company that is comprised of multiple series, each of which has separate rights, powers and duties regarding specified property and the series profits and losses associated with such property. A subsidiary of AE owns 100% of the Allegheny Series and 50% of the West Virginia Series (PATH-WV), which is a joint venture with a subsidiary of AEP. FirstEnergy is not the primary beneficiary of PATH-WV, as it does not have control over the significant activities affecting the economics of the portion of the PATH Project to be constructed by PATH-WV.
Because of the nature of PATH-WV’s operations and its FERC approved rate mechanism, FirstEnergy’s maximum exposure to loss, through AE, consists of its equity investment in PATH-WV, which was $26$27 million at March 31,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 if the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed, Penelec, PE, WP and MP, maintains 23 long-term power purchase agreements with NUG entities. The agreementsentities that were entered into pursuant to PURPA. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, these entities.
FirstEnergy has determined that for all but four of these NUG entities, its subsidiaries do not have variable interests in the entities or the entities do not meet the criteria to be considered a VIE. JCP&L, PE and WP may hold variable interests in the remaining four entities; however, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities.

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Because JCP&L, PE and WP have no equity or debt interests in the NUG entities, their maximum exposure to loss relates primarily to the above-market costs incurred for power. FirstEnergy expects any above-market costs incurred by its subsidiaries to be recovered from customers.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 March 31,June 30, 2011, were $65$55 million, $11$47 million and $5$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 held by JCP&L during the three months and six months ended March 31,June 30, 2010 were $64 million.$53 million and $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 NUG entity that WP may hold a variable interest, for which WP has taken the scope exception. As of March 31,June 30, 2011, WP’s reserve for this adverse purchase power commitment was $61$59 million, including a current liability of $18$11 million, and is being amortized over the life of the commitment.
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.

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FES and the Ohio Companies are exposed to losses under their applicable sale-leasebacksale and leaseback agreements upon the occurrence of certain contingent events. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty 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 March 31,June 30, 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 $1,187 $189  $1,348 $1,156 $192 
OE 644 485 159  635 445 190 
CEI(2)
 664 68 596  624 69 555 
TE(2)
 664 351 313  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. As a result 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 2011, FirstEnergy reached a settlement with the IRS on a research and development claim and recognized approximately $30 million of income tax benefits, including $5 million that favorably affected FirstEnergy’s effective tax rate for the second quarter and first six months of 2011. There were no other material changes to FirstEnergy’s unrecognized income tax benefits during the first threesix 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 firstsecond quarter of 2010, FirstEnergy reduced the amountrecognized approximately $70 million of unrecognizednet income tax benefits, by $57including $13 million with a corresponding adjustment tothat 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 for thisthe settled temporary tax item. There was no impact on FirstEnergy’s effective tax rate for this tax item in the first three months of 2010.
As of March 31,June 30, 2011, it is reasonably possible that approximately $48$46 million of unrecognized income tax benefits may be resolved within the next twelve months, of which approximately $6$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 the capitalization of certain costs and various state tax 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 threesix months of 2011, there were no material changes to the amount of accrued interest, except for a $6 million increase in accrued interest fromas a result of the merger with Allegheny. The reversal of accrued interest associated with the $57 million in recognized income tax benefits in 2010noted above favorably affected FirstEnergy’s effective tax rate by $5$11 million in the first quartersix months of 2010. The net amount of interest accrued as of March 31,June 30, 2011 was $10 million, compared with $3 million as of December 31, 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 $30$28 million in the first quartersix 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 in March 2010, 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 under 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. That charge reflected the anticipated increase in income taxes that will occur as a result of the change in tax law.
Allegheny recorded as deferred income tax assets the effect of net operating losses and tax credits that will more likely than not be realized through future operations and through the reversal of existing temporary differences. The tax effected net operating loss carryforwards consisted of $152 million of state net operating loss carryforwards that expire from 2019 through 2029 and $53 million of federal net operating loss carryforwards that expire from 2023 to 2029. Federal Alternative Minimum Tax credits of $25 million have an indefinite carryforward period.
Allegheny is currently under audit by the IRS for tax years 2007 and 2008. The 2009 federal return was filed and is subject to review. State tax returns for tax years 2006 through 2009 remain subject to review in Pennsylvania, West Virginia, Maryland and Virginia for certain subsidiaries of 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 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. Management believes that adequate reserves have been recognized and final settlement of these audits is not expected to have a material adverse effect on FirstEnergy’s financial condition or results of operations.

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9. COMMITMENTS, GUARANTEES AND CONTINGENCIES
(A) GUARANTEES AND OTHER ASSURANCES
As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds and LOCs. As of March 31,June 30, 2011, outstanding guarantees and other assurances aggregated approximately $3.8 billion, consisting primarily of parental guarantees ($0.8 billion), subsidiaries’ guarantees ($2.6 billion), and surety bonds and LOCs ($0.4 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. FirstEnergy views as remotebelieves the likelihood is remote that such parental guarantees of $0.2 billion (included in the $0.8 billion discussed above) as of March 31,June 30, 2011 would increase amounts otherwise payable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.
While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event,” the immediate posting of cash collateral, provision of an LOC or accelerated payments may be required of the subsidiary. As of March 31,June 30, 2011, FirstEnergy’s maximum exposure under these collateral provisions was $557$625 million, consisting of $433$522 million due to a below investment grade credit rating (of which $184$265 million is due to an acceleration of payment or funding obligation) and $124$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 $623 million, consisting of $494 million due to a below investment grade credit rating (of which $184 million is related to an acceleration of payment or funding obligation) and $129 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 $138$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, contracts entered into by the Competitive Energy Services segment, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions that 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 March 31,June 30, 2011 and forward prices as of that date, FES and AE Supply have posted collateral of $158$138 million and $5$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 $52$17 million of collateral. Depending on the volume of forward contracts and future price movements, higher amounts for margining could be required to 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.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.

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(B) ENVIRONMENTAL MATTERS
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. Compliance with environmental regulations could have a material adverse effect on FirstEnergy’s earnings and competitive position to the extent that FirstEnergy competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations.
CAA Compliance
FirstEnergy is required to meet federally-approved SO2 and NOx emissions regulations under the CAA. FirstEnergy complies with SO2 and NOx reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, combustion controls and post-combustion controls, generating more electricity from lower-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, 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 in accordance with that agreement.
In July 2008, three complaints were filed against FGCO in the U.S. District Court for the Western District of Pennsylvania 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. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these 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. and the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999) and Met-Ed. Specifically, these suits allege that “modifications” at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR permitting in violation of the CAA’s PSD program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. In September 2009, the Court granted Met-Ed’s motion to dismiss New Jersey’s and Connecticut’s claims for injunctive relief against Met-Ed, but denied Met-Ed’s motion to dismiss the claims for civil penalties. The parties dispute the scope of Met-Ed’s indemnity obligation to and from Sithe Energy, and Met-Ed is unable to predict the outcome of this matter.
In January 2009, the EPA issued a NOV to GenOn 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 from 1988 to the present without preconstruction NSR permitting in violation of the CAA’s PSD program. In May 2010, the EPA issued a second NOV to Mission, Penelec, 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 to those included in the June 2008 NOV. On July 20, 2010, the states of New York and Pennsylvania provided Mission, Penelec, NYSEG and others that have had an ownership interest in the Homer City Power Station a notification that was required 60 days prior to filing a citizen suit under the CAA. In January 2011, the DOJ filed a complaint against Penelec in the U.S. District Court for the Western District of Pennsylvania seeking injunctive relief against Penelec based on alleged “modifications” at the Homer City Power Station between 1991 to 1994 without preconstruction NSR permitting in violation of the CAA’s PSD and Title V permitting programs. The complaint was also filed against the former co-owner, New York State Electric and Gas Corporation, and various current owners of the Homer City, Station, including EME Homer City Generation L.P. and affiliated companies, including Edison International. In January 2011, another complaint was filed against Penelec and the other entities described above in the U.S. District Court for the Western District of Pennsylvania seeking damages based on the Homer City Station’sCity’s air emissions as well as certification as a class action and to enjoin the Homer City Station from operating except in a “safe, responsible, prudent and proper manner.” Penelec believes the claims are without merit and intends to defend itself against the allegations made in the complaint, but, at this time, is unable to predict the outcome of this matter. In addition, the Commonwealth of Pennsylvania and the States of New Jersey and New York intervened and have filed separate complaints regarding the Homer City Station seeking injunctive relief and civil penalties. Mission 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 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 aan 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 electric generation facilities,coal-fired plants, which collectively include 22 electric generation units:units Albright, Armstrong, Fort Martin, Harrison, Hatfield’s Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island. The letter requested information under Section 114 of the CAAIsland to determine compliance with the CAA and related requirements, including potential application of the NSR standards under the CAA, which can require the installation of additional air emission control equipment when the major modification of an existing facility results in an increase in emissions. AE has provided responsive information to this and a subsequent request but is unable to predict the outcome of this matter.
In May 2004, AE, AE Supply, MP and WP received a Notice of Intent to Sue Pursuant to CAA §7604 from the Attorneys General of New York, New Jersey and Connecticut and from the PA DEP, alleging that Allegheny performed major modifications in violation of the PSD provisions of the CAA at the following West Virginia coal-fired facilities: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 generation facilitiescoal-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 facilitiesPlants in Pennsylvania. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. In May 2006, the District Court denied Allegheny’s motion to dismiss the amended complaint. In July 2006, the Court determined that discovery would proceed regarding liability issues, but not remedies. Discovery on the liability phase closed on December 31, 2007, and summary judgment briefing was completed during the first quarter of 2008. In November 2008, the District Court issued a Memorandum Order denying all motions for summary judgment and establishing certain legal standards to govern at trial. In December 2009, a new trial judge was assigned to the case, who then entered an order granting a motion to reconsider the rulings in the November 2008 Memorandum Order. In April 2010, the new judge issued an opinion, again denying all motions for summary judgment and establishing certain legal standards to govern at trial. TheA non-jury trial on liability only was held in September 2010. Plaintiffs filed their proposed findings of fact and conclusions of law in December 2010, Allegheny made its related filings in February 2011 and plaintiffs filed their responses in April 2011. The parties are awaiting a decision from the District Court, but there is no deadline for that decision.
In September 2007, Allegheny also received a NOV from the EPA alleging NSR and PSD violations under the CAA, as well as Pennsylvania and West Virginia state laws at the Hatfield’s Ferry and Armstrong generation facilitiesPlants in Pennsylvania and the Fort Martin and Willow Island generation facilitiescoal-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 power stationcoal-fired plant for NOX, SO2 and mercury, based on a PJM declaration that the stationplant is vital to reliability in the Baltimore/Washington DC metropolitan area, which PJM determined in 2006. Pursuant to the legislation, the Maryland Department of the Environment (MDE) passed alternate NOX and SO2 limits for R. Paul Smith, which became effective in April 2009. However, R. Paul Smith is still required to meet the Healthy Air Act mercury reductions of 80% beginning in 2010. The statutory exemption does not extend to R. Paul Smith’s CO2 emissions. Maryland issued final regulations to implement RGGI requirements in February 2008. Ten RGGI auctions have been held through the end of calendar year 2010. RGGI allowances are also readily available in the allowance markets, affording another mechanism by which to secure necessary allowances. On March 14, 2011, MDE requested PJM perform an analysis to determine if termination of operation at R. Paul Smith would adversely impact the reliability of electrical service in the PJM region under current system conditions. FirstEnergy is unable to predict the outcome of this matter.

 

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In January 2010, the WVDEP issued a NOV for opacity emissions at Allegheny’s Pleasants generating facility.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 NOx and SO2 emissions in two phases (2009/2010 and 2015), ultimately capping SO2SO2 emissions in affected states to 2.5 million tons annually and NOx emissions to 1.3 million tons annually. In 2008, the U.S. Court of Appeals for the District of Columbia 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 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 NOx and SO2SO2 emissions in two phases (2012 and 2014), ultimately capping SO2SO2 emissions in affected states to 2.62.4 million tons annually and NOx emissions to 1.31.2 million tons annually. The EPA proposed a preferred regulatory approach thatCSAPR allows trading of NOx and SO2 emission allowances between power plants located in the same state and severely limits interstate trading of NOx and SO2 emission allowances. The EPA also requested comment on two alternative approaches—the first eliminates interstate trading of NOx and SO2 emission allowances and the second eliminates trading of NOx and SO2 emission allowances in its entirety. Depending on the actions taken by the EPA with respect to CATR, the proposed MACT regulations discussed below and any future regulations that are ultimately implemented,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
On March 16, 2011, the EPA released its MACT proposal to establish emission standards for mercury, hydrochloric acid and various metals for electric generating units. Depending on the action taken by the EPA and how any future regulations are ultimately implemented, FirstEnergy’s future cost of compliance with MACT regulations may be substantial and changes to FirstEnergy’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, in June 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, proposals to ensure that 10% of electricity used in the United States comes from renewable sources by 2012, to increase to 25% by 2025, to implement an economy-wide cap-and-trade program to reduce GHG emissions by 80% by 2050. Certain states, primarily the northeastern states participating in the RGGI and western states, led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.
In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that required FirstEnergy to measure 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. Until July 1, 2011, this emissions applicability threshold will only apply if PSD is triggered by non-CO2 pollutants.

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At the international level, the Kyoto Protocol, signed by the U.S. in 1998 but never submitted for ratification by the U.S. Senate, was intended to address global warming by reducing the amount of man-made GHG, including CO2, emitted by developed countries by 2012. A December 2009 U.N. Climate Change Conference in Copenhagen did not reach a consensus on a successor treaty to the Kyoto Protocol, but did take note of the Copenhagen Accord, a non-binding political agreement that recognized the scientific view that the increase in global temperature should be below two degrees Celsius; includes 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 establishes the “Copenhagen Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. To the extent that they have become a party to the Copenhagen Accord, developed economies, such as the European Union, Japan, Russia and the United States, would commit to quantified economy-wide emissions targets from 2020, while developing countries, including Brazil, China and India, would agree to take mitigation actions, subject to their domestic measurement, reporting and verification.

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In 2009, the U.S. Court of Appeals for the Second Circuit and the U.S. Court of Appeals for the Fifth Circuit reversed and remanded lower court decisions that had dismissed complaints alleging damage from GHG emissions on jurisdictional grounds. However, a subsequent ruling from the U.S. Court of Appeals for the Fifth Circuit reinstated the lower court dismissal of a complaint alleging damage from GHG emissions. These cases involve common law tort claims, including public and private nuisance, alleging that GHG emissions contribute to global warming and result in property damages. The U.S. Supreme Court granted a writ of certiorari to review the decision of the Second Circuit. Oral argument was held on April 19,On June 20, 2011, and a decision is expected by July 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, the 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. In April 2009, the U.S. Supreme Court reversed one significant aspect of the Second Circuit’s opinion and decided that Section 316(b) of the 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. On March 28, 2011, the EPA released a new proposed regulation under Section 316(b) of the Clean Water Act generally requiring fish impingement to be reduced to a 12% annual average and studies to be conducted at the majority of our existing generating facilities to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic life. On July 19, 2011, the EPA extended the public comment period for the new proposed Section 316(b) regulation by 30 days but stated its schedule for issuing a final rule remains July 27, 2012. FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore power plant’s water intake channel to divert fish away from the plant’s water intake system. In November 2010, the Ohio EPA issued a 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 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 generation facility.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 September 13, 2011.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 has not acted onagreed with PA DEP’s recommendation. Ifrecommended sulfate impairment designation. PA DEP’s goal is to submit a final water quality standards regulation, incorporating the sulfate impairment designation is approved, Pennsylvaniafor EPA approval by May, 2013. PA DEP will then need to develop a TMDL limit for the river, a process that will take aboutapproximately 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.
In December 2009, in an advanced notice of public rulemaking, the EPA asserted that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. In May 2010, the EPA proposed two options for additional regulation of coal combustion residuals, including the option of regulation as a special waste under the EPA’s hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. FirstEnergy’s future cost of compliance with any coal combustion residuals regulations that may be 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 Little 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 March 31,June 30, 2011, based on estimates of the total costs of cleanup, the Utility RegistrantsRegistrants’ proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $104$133 million (JCP&L — $69 million, TE — $1 million, CEI — $1 million, FGCO — $1 million and FirstEnergy — $32$61 million) have been accrued through March 31,June 30, 2011. Included in the total are accrued liabilities of approximately $64$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. 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. In November 2010, the Supreme Court issued an order denying Plaintiffs’ motion. The Court’s order effectively ends the class action attempt, and leaves only nine (9) plaintiffs to pursue their respective individual claims. The remaining individual plaintiffs have not takenyet to take any affirmative steps to pursue their individual claims.
Nuclear Plant Matters
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of March 31,June 30, 2011, FirstEnergy had approximately $2 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. FirstEnergy provides an additional $15 million parental guarantee associated with the funding of decommissioning costs for these units. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy’s nuclear decommissioning trustsNDT fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy’s obligation to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the nuclear decommissioning trusts.NDT. The NRC issued guidance anticipating an increase in low-level radioactive waste disposal costs associated with the decommissioning of FirstEnergy’s nuclear facilities. On March 28, 2011, FENOC submitted its biennial report on nuclear decommissioning funding to the NRC. This submittal identified a total shortfall in nuclear decommissioning funding for Beaver Valley Unit 1 and Perry of approximately $92.5 million. This estimate encompasses the shortfall covered by the existing $15On June 24, 2011, FENOC submitted a $95 million parental guarantee. FENOC agreed to increase the parental guarantee to $95 million within 90 days of the submittal.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, thea 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 regardingchallenging 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) the cost of mitigating a severe accident mitigation alternatives at Davis-Besse. On May 6, 2011, FENOC is currently evaluating these developments and consideringfiled an appropriate response. appeal with the NRC Commissioners from the order granting a hearing on the Davis-Besse license renewal application.
On April 14, 2011, a group of environmental organizations petitioned the NRC Commissioners to suspend allcertain pending nuclear license renewallicensing 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 event 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 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
In February 2010, a class action lawsuit was filed in Geauga County Court of Common Pleas against FirstEnergy, CEI and OE seeking declaratory judgment and injunctive relief, as well as compensatory, incidental and consequential damages, on behalf of a class of customers related to the reduction of a discount that had previously been in place for residential customers with electric heating, electric water heating, or load management systems. The reduction in the discount was approved by the PUCO. In March 2010, the named-defendant companies filed a motion to dismiss the case due to the lack of jurisdiction of the court of common pleas. The court granted the motion to dismiss on September 7, 2010. The plaintiffs appealed the decision to the Court of Appeals of Ohio, 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.
10. REGULATORY MATTERS
(A) RELIABILITY INITIATIVES
Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES, FGCO, FENOC, and ATSI and TrAIL Company.TrAIL. The NERC asis the ERO is charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including ReliabilityFirstCorporation. All of FirstEnergy’s facilities are located within the ReliabilityFirstregion. FirstEnergy actively participates in the NERC and ReliabilityFirststakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by the ReliabilityFirstCorporation.
FirstEnergy believes that it generally is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such items are found, FirstEnergy develops information about the item and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an item to 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. This event did not result in a fault, outage, operation of protective equipment, or any other meaningful electric effect on any FirstEnergy transmission facilities or systems. On August 25, 2010, ReliabilityFirstissued a Notice of Enforcement to investigate the incident. FirstEnergy submitted a data response to ReliabilityFirston September 27, 2010. In March 2011, ReliabilityFirstsubmitted its proposed findings and settlement. At this time, FirstEnergy is evaluating ReliabilityFirst’s proposal and is unable to predict thesettlement, although a final outcome of this investigation.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 violation investigations with regard to certain matters of compliance by Allegheny.

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(B) MARYLAND
In 1999, Maryland adopted electric industry restructuring legislation, which gave PE’s Maryland retail electric customers the right to choose their electricity generation suppliers. PE remained obligated to provide standard offer generation service (SOS) at capped rates to residential and non-residential customers for various periods. The longest such period, for residential customers, expired on December 31, 2008. PE implemented a rate stabilization plan in 2007 that was designed to transition customers from capped generation rates to rates based on market prices and that concluded on December 31, 2010. PE’s transmission and distribution rates for all customers are subject to traditional regulated utility ratemaking (i.e., cost-based rates).
By statute enacted in 2007, the obligation of Maryland utilities to provide SOSstandard 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. In August 2007, PE filed a plan for seeking bids to serve its Maryland residential load for the period after the expiration of rate caps. The MDPSC approved the plan and PE now conducts rolling auctions to procure the power supply necessary to serve its customer load.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 no further proceedings have been set by the MDPSC in this matter.
In September 2007, the MDPSC issued an order that required the Maryland utilities to file detailed plans for how they will meet the “EmPOWER Maryland” proposal that in Maryland, electric consumption be reduced by 10% and electricity demand be reduced by 15%, in each case by 2015. In October 2007, PE filed its initial report on energy efficiency, conservation and demand reduction plans in connection with this order. The MDPSC conducted hearings on PE’s and other utilities’ plans in November 2007 and May 2008.
In a related development, theThe Maryland legislature in 2008 adopted a statute codifying the EmPOWER Maryland goals. In 2008, PE filed its comprehensive plans for attempting to achieve those goals, asking the MDPSC to approve programs for residential, commercial, industrial, and governmental customers, as well as a customer education program, and a pilot deployment of Advanced Utility Infrastructure (AUI) that Allegheny had previously tested in West Virginia.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. The AUI pilot was placed on a separate track to be re-examined after further discussion with the Staff of the MDPSC and other stakeholders. Meanwhile, extensive meetings with the MDPSC Staff and other stakeholders to discuss details of PE’s plans for additional and improved programs for the period 2012-2014 began in April 2011 and those programs are to be filed by September 1, 2011.
In March 2009, the Maryland PSCMDPSC issued an order suspending until further notice the right of all electric and gas utilities in the state to terminate service to residential customers for non-payment of bills. The MDPSC subsequently issued an order making various rule changes relating to terminations, payment plans, and customer deposits that make it more difficult for Maryland utilities to collect deposits or to terminate service for non-payment. PE and several other utilities filed requests for reconsideration of various parts of the order, which were denied. The MDPSC is continuing to conduct hearings and collect data on payment plan and related issues and has adopted a set of proposed regulations that expand the summer and winter “severe weather” termination moratoria when temperatures are very high or very low, from one day, as provided by statute, to three days on each occurrence.

 

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On March 24, 2011, the MDPSC held an initial hearing to discuss possible new regulations relating to service interruptions, storm response, call center metrics, and related reliability standards. The proposed rules included provisions for civil penalties for non-compliance. Numerous parties filed comments on the proposed rules and participated in the hearing, with many noting issues of cost and practicality relating to implementation. Concurrently, theThe Maryland legislature is consideringpassed a bill addressing the same topics. The final bill passed 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 is directed 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.
In December 2009, PErules, with proposed rules to be filed an application withby September 15, 2011. Separately, on April 7, 2011, the MDPSC for authorizationinitiated a rulemaking with respect to constructissues related to contact voltage. On June 3, 2011, the Maryland portions ofMDPSC’s Staff issued a report and draft regulations. Comments on the PATH Projectdraft regulations were submitted on June 17, 2011, and a hearing was held July 7, 2011. Final regulations related to be owned by PATH Allegheny Maryland Transmission Company, LLC, which is owned by Potomac Edison and PATH-Allegheny. On February 28, 2011, PE withdrew its application. See “Transmission Expansion” in the Federal Regulation and Rate Matters section for further discussion of this matter.contact voltage have not yet been adopted.
(C) NEW JERSEY
JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers, costs incurred under NUG agreements, and certain other stranded costs, exceed amounts collected through BGS and NUG rates and market sales of NUG energy and capacity. As of March 31, 2011, the accumulated deferred cost balance was a credit of approximately $102 million. To better align the recovery of expected costs, in July 2010, JCP&L filed a request to decrease the amount recovered for the costs incurred under the NUG agreements by $180 million annually, which the NJBPU approved, allowing the change in rates to become effective March 1, 2011.
In March 2009 and again in February 2010, JCP&L filed annual SBC Petitions with the NJBPU that included a requested zero level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009 estimated at $736 million (in 2003 dollars). Both matters are currently pending beforeIn its order of June 15, 2011, the NJBPU.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 ESP, which expires on May 31, 2011, that provides for generation supplied through a CBP. The 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).
In March 2010, the Ohio Companies filed an application for a new ESP, which the PUCO approved in August 2010, with certain modifications. The new ESP will go into effect on June 1, 2011 and conclude on May 31, 2014. The material terms of the new ESP include: generation supplied through a CBP similar to the one used in May 2009 and the one proposed on the October 2009 MRO filingcommencing 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 tranches assigned post-auction; a 6% generation discount to certain low income customers provided by the Ohio Companies through a bilateral wholesale contract with FES;FES (FES is one of the wholesale suppliers to the Ohio Companies); no increase in base distribution rates through May 31, 2014; and a new distribution rider, Delivery Capital Recovery Rider (Rider DCR), to recover a return of, and on, capital investments in the delivery system. Rider DCR substitutes for Rider DSI which terminates under the current ESP. The Ohio Companies also agreed not to recover from retail customers 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-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 agreed to additional matters related to energy efficiency and alternative energy requirements. Many of the existing riders approved in the previous ESP remain in effect, with some modifications. The new ESP resolved proceedings pending at the PUCO regarding corporate separation, elements of the smart grid proceeding and expenses related to the ESP.
Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total annual energy savings equivalent to 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.

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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. Because of the delay in issuing the Order, the launch of the programs included in the plan for 2010 was delayed and will launch during the second quarter of this year. As a result, OE fell short of its statutory 2010 energy efficiency and peak demand reduction benchmarks. Therefore,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 modify the Companies’ 2010 (and 2011 and 2012) energy efficiency benchmarks when addressing the portfolio plan, the Ohio Companies were not certain of their 2010 energy efficiency obligations. Therefore, CEI and TE (each of which achieved its 2010 energy efficiency and peak demand reduction statutory benchmarks) also requested an amendment if and only to the degree one was deemed necessary to bring these them into compliance with their yet-to-be-defined modified benchmarks. 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 Companiescompanies 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 2009.2009 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. In March 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. FES also applied for a force majeure determination from the PUCO regarding a portion of their compliance with the 2009 solar energy resource benchmark. On February 23, 2011, the PUCO granted FES’ force majeure request for 2009 and increased its 2010 benchmark by the amount of SRECs that FES was short of in its 2009 benchmark. In July 2010, the Ohio Companies initiated an additional RFP to secure RECs and solar RECs needed to meet the Ohio Companies’ alternative energy requirements as set forth in SB221 for 2010 and 2011 and executed related contracts in August 2010. On April 15, 2011, the Ohio Companies filed an application seeking an amendment to each of their 2010 alternative energy requirements for solar RECs generated in Ohio on the basis that an insufficient quantity of solar resources are available in the market but reflecting solar RECs that they have obtained and providing additional information regarding efforts to secure solar RECs. 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 rates and what they pay with the new credit in place. Tariffs implementing this new credit went into effect in March 2010. In April 2010, the PUCO issued a Second Entry on Rehearing that expanded the group of customers to which the new credit would apply and authorized deferral for the associated additional amounts. The PUCO also stated that it expected that the new credit would remain in place through at least the 2011 winter season and charged its staff to work with parties to seek a long term solution to the issue. Tariffs implementing this newly expanded credit went into effect in May 2010 and the proceeding remains open. The hearing on the matter was held in February 2011. The matter has now been briefedPUCO 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 awaitfiled their responses on July 5, 2011. The PUCO has not yet acted on the PUCO’s decision.applications for rehearing.

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(E) PENNSYLVANIA
The PPUC entered an Order on March 3, 2010 that denied the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, directed Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructed Met-Ed and Penelec to work with the various intervening parties to file a recommendation to the PPUC regarding the establishment of a separate account for all marginal transmission losses collected from ratepayers plus interest to be used to mitigate future generation rate increases beginning January 1, 2011. In March 2010, Met-Ed and Penelec filed a Petition with the PPUC requesting that it stay the portion of the March 3, 2010 Order requiring the filing of tariff supplements to end collection of costs for marginal transmission losses. The PPUC granted the requested stay until December 31, 2010. Pursuant to the PPUC’s order, Met-Ed and Penelec filed plans to establish separate accounts for marginal transmission loss revenues and related interest and carrying charges and forcharges. Pursuant to the use of these funds to mitigate future generation rate increases whichplan approved by the PPUC, approved.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. The argument beforeOn June 14, 2011, the Commonwealth Court en banc, was heldissued 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 December 2010.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 inthrough the appealjudicial process and therefore expect to fully recover the approximately $252.7$254 million ($188.0189 million for Met-Ed and $64.7$65 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011.
In May 2008, May 2009 and May 2010, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider for the annual periods between June 1, 2008 to December 31, 2010, including marginal transmission losses as approved by the 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.
Met-Ed and Penelec filed with the PPUC a generation procurement plan covering the period January 1, 2011 through May 31, 2013. The plan is designed to provide adequate and reliable service through a prudent mix of long-term, short-term and spot market generation supply with a staggered procurement schedule that varies by customer class, using a descending clock auction. In August 2009, the parties to the proceeding filed a settlement agreement of all but two issues, and the PPUC entered an Order approving the settlement and the generation procurement plan in November 2009. Generation procurement began in January 2010.
In February 2010, Penn filed a Petition for Approval of its Default Service Plan for the period June 1, 2011 through May 31, 2013. In July 2010, the parties to the proceeding filed a Joint Petition for Settlement of all issues. Although the PPUC’s Order approving the Joint Petition held that the provisions relating to the recovery of MISO exit fees and one-time PJM integration costs (resulting from Penn’s June 1, 2011 exit from MISO and integration into PJM) were approved, it made such provisions subject to the approval of cost recovery by FERC. Therefore, Penn may not put these provisions into effect until FERC has approved the recovery and allocation of MISO exit fees and PJM integration costs.
Pennsylvania adopted Act 129 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 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 held 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 Commonwealth Court pending possible settlement of WP’s SMIP. In September 2010, WP filed an amended EE&C Plan that is less reliant on smart meter deployment, which the PPUC approved in January 2011.

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Met-Ed, Penelec and Penn jointly filed a SMIP with the PPUC in August 2009. This plan proposed 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 of 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 SMIP as modified by the ALJ, including: ensuring that the smart meters to be deployed include the capabilities listed in the PPUC’s Implementation Order; denying the recovery of interest through the automatic adjustment clause; providing for the recovery of reasonable and prudent costs net of resulting savings from installation and use of smart meters; and requiring that administrative start-up costs be expensed and the costs incurred for research and development in the assessment period be capitalized. In April 2010, the PPUC adopted a Motion by Chairman Cawley that modified the ALJ’s initial decision, and decided various issues regarding the SMIP for Met-Ed, Penelec and Penn. The PPUC entered its Order in June 2010, consistent with the Chairman’s Motion. Met-Ed, Penelec and Penn filed a Petition for Reconsideration of a single portion of the 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.
In August 2009, WP filed its original SMIP, which provided for extensive deployment of smart meter infrastructure with replacement of all of WP’s approximately 725,000 meters by the end of 2014. In December 2009, WP filed a motion to reopen the evidentiary record to submit an alternative smart meter plan proposing, among other things, a less-rapid deployment of smart meters. In an Initial Decision dated April 29, 2010, an ALJ determined that WP’s alternative smart meter deployment plan, which contemplated deployment of 375,000 smart meters by May 2012, complied with the requirements of Act 129 and recommended approval of the alternative plan, including WP’s proposed cost recovery mechanism.
In light of the significant expenditures that would be associated with its smart meter deployment plans and related infrastructure upgrades, as well as its evaluation of recent PPUC decisions approving less-rapid deployment proposals by other utilities, WP re-evaluated its Act 129 compliance strategy, including both its plans with respect to smart meter deployment and certain smart meter dependent aspects of the EE&C Plan. In October 2010, WP and Pennsylvania’s Office of Consumer AdvocateOCA 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. The proposed settlement remains subject to review byOn May 3, 2011, the ALJ who will prepareissued an Initial Decision recommending that the PPUC approve the Amended Joint Petition for considerationFull Settlement. The PPUC approved the Initial Decision by the PPUC.order entered June 30, 2011.

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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. TheOn April 29, 2011, the PPUC has not yet initiated that investigation.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.

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(F) VIRGINIA
In September 2010, PATH-VA filed an application with the Virginia SCCVSCC 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.
(G) WEST VIRGINIA
In August 2009, MP and PE filed with the WVPSC a request to increase retail rates, by approximately $122.1 million annually, effective June 10, 2010. In January 2010, MP and PE filed supplemental testimony discussing a tax treatment change that would result in a revenue requirement approximately $7.7 million lower than the requirement included in the original filing. In addition, in December 2009, subsidiaries of MP and PE completed a securitization transaction to finance certain costs associated with the installation of scrubbers at the Fort Martin generating station, which costs would otherwise have been included in the request for rate recovery. Consequently,was amended through subsequent filings. MP and PE ultimately requested an annual increase in retail rates of approximately $95 million, rather than $122.1 million. In April 2010, MP and PE filed with the WVPSC a Joint Stipulation and Agreement of Settlement reached with the other parties in the proceeding that provided for:
a $40 million annualized base rate increase effective June 29, 2010;
a deferral of February 2010 storm restoration expenses in West Virginia over a maximum five-year period;
an additional $20 million annualized base rate increase effective in January 2011;
a decrease of $20 million in ENEC rates effective January 2011, which amount is deferred for later recovery in 2012; and
a moratorium on filing for further increases in base rates before December 1, 2011, except under specified circumstances.
The WVPSC approved the Joint Petition and Agreement of Settlement in June 2010.
In 2009, the West Virginia Legislature enacted the Alternative and Renewable Energy Portfolio Act (Portfolio Act), which generally requires that a specified minimum percentage of electricity sold to retail customers in West Virginia by electric utilities each year be derived from alternative and renewable energy resources according to a predetermined schedule of increasing percentage targets, including ten percent by 2015, fifteen percent by 2020, and twenty-five percent by 2025. In November 2010, the WVPSC issued Rules Governing Alternative and Renewable Energy Portfolio Standard (RPS Rules), which became effective on January 4, 2011. Under the RPS Rules, on or before January 1, 2011, each electric utility subject to the provisions of this rule was required to prepare an alternative and renewable energy portfolio standard compliance plan and file an application with the WVPSC seeking approval of such plan. MP and PE filed their combined compliance plan in December 2010. 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 MP is entitled to all alternative &and renewable energy resource credits associated with the electric energy, or energy and capacity, that MP is required to purchase pursuant to electric energy purchase agreements between MP and three non-utility electric generating facilities in WV. The City of New Martinsville and Morgantown Energy Associates, each the owner of one of the contracted resources, has filed anparticipated in the case in opposition to the Petition.

 

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(H) FERC MATTERS
Rates for Transmission Service Between MISO and PJM
In November 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as SECA) during a 16-month transition period. In 2005, the FERC set the SECA for hearing. The presiding ALJ issued an initial decision in August 2006, rejecting the compliance filings made by MISO, PJM and the transmission owners, and directing new compliance filings. This decision was subject to review and approval by the FERC. In May 2010, FERC issued an order denying pending rehearing requests and an Order on Initial Decision which reversed the presiding ALJ’s rulings in many respects. Most notably, these orders affirmed the right of transmission owners to collect SECA charges with adjustments that modestly reduce the level of such charges, and changes to the entities deemed responsible for payment of the SECA charges. The Ohio Companies were identified as load serving entities responsible for payment of additional SECA charges for a portion of the SECA period (Green Mountain/Quest issue). FirstEnergy executed settlements with AEP, Dayton and the Exelon parties to fix FirstEnergy’s liability for SECA charges originally billed to Green Mountain and Quest for load that returned to regulated service during the SECA period. The AEP, Dayton and Exelon, settlements were approved by the FERC in November 2010, and the relevant payments made. The Utilitiessubsidiaries 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
In April 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 in August 2009. The court affirmed FERC’s ratemaking treatment for existing transmission facilities, but found that FERC had not supported its decision to allocate costs for 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 then reply comments on later dates. PJM filed certain studies with FERC on April 13, 2010, in response to the FERC order. PJM’s filing demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain eastern utilities in PJM bearing the majority of the costs. Numerous parties filed responsive comments or studies on May 28, 2010 and reply comments on June 28, 2010. FirstEnergy and a number of other utilities, industrial customers and state commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. 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 the 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 for moving its transmission rate into PJM’s tariffs. FirstEnergy expects ATSI to enter PJM on June 1, 2011, and that if legal proceedings regarding its rate are outstanding at that time, ATSI will be permitted to start charging its proposed rates, subject to refund. On April 1, 2011, the MISO Transmission Owners (including ATSI) filed proposed tariff language that describes the mechanics of collecting and administering MTEP costs from ATSI-zone ratepayers. From March 20, 2011 through April 1, 2011, FirstEnergy, PJM and the MISO submitted numerous filings for the purpose of effecting movement of the ATSI zone to PJM on June 1, 2011. These filings include clean-up ofamendments to the MISO’s tariffs (to remove the ATSI zone), submission of load and generation interconnection agreements to reflect the move into PJM, and submission of changes to PJM’s tariffs to support the move into PJM.
On May 31, 2011, FERC proceedings are pending in which ATSI’sissued orders that address the proposed ATSI transmission rate, and certain parts of the exit fee payable to MISO tariffs that reflect the mechanics of transmission cost allocationsallocation and collection. In its May 31, 2011 orders, FERC approved ATSI’s proposal to move the ATSI formula rate into the PJM tariff without significant change. Speaking to ATSI’s proposed treatment of the MISO’s exit fees and charges for transmission costs that were allocated to the ATSI zone, FERC required ATSI to present a cost-benefit study that demonstrates that the benefits of the move for transmission customers exceed the costs of any such move, which FERC had not previously required. Accordingly, FERC ruled that these costs must be removed from ATSI’s proposed transmission rates until such time as ATSI files and FERC approves the cost-benefit study. On June 30, 2011, ATSI submitted the compliance filing that removed the MISO exit fees and transmission cost allocation charges from ATSI’s proposed transmission rates. Also on June 30, 2011, ATSI requested rehearing of FERC’s decision to require a cost-benefit 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 and 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 are under review.MISO. ATSI did not and does not agree that these costs should be charged to ATSI but, in order to settle the case and all claims associated with the case, ATSI agreed to a one-time payment of $1.8 million to the MISO. This settlement agreement has been submitted for FERC’s review and approval. The final outcome of thesethose proceedings that address the remaining open issues related to ATSI’s move into PJM and their impact, if any, on FirstEnergy cannot be predicted.predicted at this time.

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MISO Multi-Value Project Rule Proposal
In July 2010, MISO and certain MISO transmission owners jointly filed with FERC their proposed cost allocation methodology for certain new transmission projects. The new transmission projects—described as MVPs—MVPs — are a class of MTEP projects.transmission projects that are approved via MISO’s formal transmission planning process (the MTEP). The filing parties proposed to allocate the costs of MVPs by means of a usage-based charge that will be applied to all loads within the MISO footprint, and to energy transactions that call for power to be “wheeled through” the MISO as well as to energy transactions that “source” in the MISO but “sink” outside of MISO. The filing parties expect that the MVP proposal will fund the costs of large transmission projects designed to bring wind generation from the upper Midwest to load centers in the east. The filing parties requested an effective date for the proposal of July 16, 2011. On August 19, 2010, MISO’s Board approved the first MVP project — the “Michigan Thumb Project.” Under MISO’s proposal, the costs of MVP projects approved by MISO’s Board prior to the anticipated June 1, 2011 effective date of FirstEnergy’s integration into PJM would continue to be allocated to FirstEnergy. MISO estimated that approximately $15 million in annual revenue requirements would be allocated to the ATSI zone associated with the Michigan Thumb Project upon its completion.
In September 2010, FirstEnergy filed a protest to the MVP proposal arguing that MISO’s proposal to allocate costs of 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 integration into PJM, it would be unjust and unreasonable to allocate any MVP costs to the ATSI zone, or to ATSI. Numerous other parties filed pleadings on MISO’s MVP proposal.
In December 2010, FERC issued an order approving the MVP proposal without significant change. 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 attachattached 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 usage-based, costs could not be applied to ATSI, which is a stand-alone transmission company that does not use the transmission system. FirstEnergy also renewed its arguments regarding cost causation and the impropriety of allocating costs to the ATSI zone or to ATSI.
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.
PJM Calculation Error
In March 2010, MISO filed two complaints at FERC against PJM relating to a previously-reported modeling error in PJM’s system that impacted the manner in which market-to-market power flow calculations were made between PJM and MISO since April 2005. MISO claimed that this error resulted in PJM underpaying MISO by approximately $130 million over the time period in question. Additionally, MISO alleged that PJM did not properly trigger market-to-market settlements between PJM and MISO during times when it was required to do so, which MISO claimed may have cost it $5 million or more. As PJM market participants, AE Supply and MP may be liable for a portion of any refunds ordered in this case. PJM, Allegheny and other PJM market participants filed responses to MISO complaints and PJM filed a related complaint at FERC against MISO claiming that MISO improperly called for market-to-market settlements several times during the same time period covered by the two MISO complaints filed against PJM, which PJM claimed may have cost PJM market participants $25 million or more. On January 4, 2011, an Offer of Settlement was filed at FERC that, if approved, would resolve all pending issues in the dispute. The Offer of Settlement calls for the withdrawal of all pending complaints with no payments being made by any parties. Initial comments on the Offer of Settlement were filed at FERC on January 24, 2011. FirstEnergy and Allegheny Energy filed comments supporting the proposed settlement. A report on the partially contested settlement was issued by the settlement judge to the FERC on March 9, 2011. On March 16, 2011, the settlement judge terminated the settlement proceedings and forwarded the partially contested settlement to the FERC for review. The case is awaiting a decision by the FERC.
California Claims Matters
In October 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the California Department of Water Resources (CDWR) during 2001. The settlement proposal claims that CDWR is owed approximately $190 million for these alleged overcharges. This proposal was made in the context of mediation efforts by the FERC and the United States Court of Appeals for the Ninth Circuit in pending proceedings to resolve all outstanding refund and other claims, including claims of alleged price manipulation in the California energy markets during 2000 and 2001. The Ninth Circuit has since remanded one of those proceedings to the FERC, which arises out of claims previously filed with the FERC by the California Attorney General on behalf of certain California parties against various sellers in the California wholesale power market, including AE Supply (the Lockyer case). AE Supply and several other sellers have filed motions to dismiss the Lockyer case. In March 2010, the judge assigned to the case entered an opinion that granted the motions to dismiss filed by AE Supply and other sellers and dismissed the claims of the California Parties. In April 2010, the California parties filed exceptions toOn May 4, 2011, FERC affirmed the judge’s ruling with the FERC, and briefing is complete on those exceptions. The parties are awaiting a ruling from the FERC on the exceptions.ruling.

 

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In June 2009, the California Attorney General, on behalf of certain California parties, filed a second lawsuitcomplaint with the FERC against various sellers, including AE Supply (the Brown case), again seeking refunds for trades in the California energy markets during 2000 and 2001. The above-noted trades with CDWR are the basis for the joining ofincluding AE Supply in this new lawsuit.complaint. AE Supply has filed a motion to dismiss the Brown casecomplaint that is pending beforewas granted by FERC on May 24, 2011. On June 23, 2011, the FERC. No scheduling order has been entered inCalifornia Attorney General requested rehearing of the Brown case. Allegheny intends to vigorously defend against these claims butMay 24, 2011 order. FirstEnergy cannot predict their outcome.the outcome of this matter.
Transmission Expansion
TrAIL Project.TrAIL is a 500kV500 kV transmission line currently under construction that will extendextending from southwest Pennsylvania through West Virginia and into northern Virginia. On April 15,Effective May 19, 2011, theall segments of TrAIL 500 kV line segment from Meadowbrook substation to Loudoun substation in Virginia was successfullywere energized and is carrying load. The other segments are planned to be energized in May. The entire TrAIL line is scheduled to be completed and placed in service no later than June 2011.service.
PATH Project.The PATH Project is comprised of a 765 kV transmission line that iswas proposed to extend from West Virginia through Virginia and into Maryland, modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland.
PJM initially authorized construction of the PATH Project in June 2007 and, on June 17, 2010, requested that PATH, LLC proceed with all efforts related to the PATH Project, including state regulatory proceedings, assuming a required in-service date of June 1, 2015.2007. 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 potential need for the project as part of its continuing RTEP process. PJM stated that its action did not constitute a directive to FirstEnergy and AEP to cancel or abandon the PATH Project. PJM further stated that it will complete a more rigorous analysis of the PATH Project and other transmission requirements and its Board will review this comprehensive analysis as part of its consideration of the 2011 RTEP. On February 28, 2011, affiliates of FirstEnergy and AEP filed motions or notices to withdraw applications for authorization to construct the project that were pending before state commissions in West Virginia, Virginia and Maryland. Withdrawal was deemed effective upon filing the notice with the MDPSCMDPSC. The WVPSC and the WVPSC hasVSCC have granted the motion to withdraw. The VSCC has not ruled on the motionmotions 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 proceeding or whether it will have a material impact on its operating results.time.
Sales to Affiliates
FES has received authorization from the FERC to make wholesale power sales to affiliated regulated utilities in New Jersey, Ohio, and Pennsylvania. FES actively participates in auctions conducted by or on behalf the regulated affiliates to obtain power necessary to meet the utilities’ POLR obligations. AE Supply, a merchant affiliate acquired in the FirstEnergy-Allegheny merger, also participates in these auctions, and obtains prior FERC authorization when necessary to make sales to FE affiliates.
11. STOCK-BASED COMPENSATION PLANS
FirstEnergy has four types of stock-based compensation programs including— LTIP, EDCP, ESOP and DCPD, as described below.
In addition, Allegheny’s stock-based awards were converted into First EnergyFirstEnergy stock-based awards as of the date of the merger. These awards, referred to below as converted Allegheny awards, were adjusted in terms of the number of awards and, where applicable, the exercise price thereof, to reflect the merger’s common stock exchange ratio of 0.667 of a share of FirstEnergy common stock for each share of Allegheny common stock.

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(A) LTIP
FirstEnergy’s LTIP includes four forms of stock-based compensation awards — stock options, performance shares, restricted stock and restricted stock units.
Under FirstEnergy’s LTIP, total awards cannot exceed 29.1 million shares of common stock or their equivalent. Only stock options, restricted stock and restricted stock units have currently been designated to be settled in common stock, with vesting periods ranging from two months to ten years. Performance share awards are currently designated to be paid in cash rather than common stock and therefore do not count against the limit on stock-based awards. There were 6.35.6 million shares available for future awards as of March 31,June 30, 2011.
Restricted Stock and Restricted Stock Units
Restricted common stock (restricted stock) and restricted stock unit (stock unit) activity was as follows:
     
  ThreeSix Months 
  Ended 
  March 31,June 30, 2011 
 
Restricted stock and stock units outstanding as of January 1, 2011  1,878,022 
Granted  223,161891,881 
Converted Allegheny restricted stock  645,197 
Exercised  (422,031428,686)
Forfeited  (37,18271,775)
    
Restricted stock and stock units outstanding as of March 31,June 30, 2011  2,287,1672,914,639 
    
The 223,161891,881 shares of restricted common stock granted during the threesix months ended March 31,June 30, 2011 had a grant-date fair value of $8.2$33.2 million and a weighted-average vesting period of 1.862.74 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 forduring the threesix months ended March 31,June 30, 2011 and 2010 for restricted stock and restricted stock units, net of amounts capitalized, was approximately $16$27 million and $6$20 million, respectively.

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Stock Options
Stock option activity for the threesix months ended March 31,June 30, 2011 was as follows:
                
 Weighted  Weighted 
 Average  Average 
 Number of Exercise  Number of Exercise 
Stock Option Activities Shares Price  Shares Price 
 
Stock options outstanding as of January 1, 2011 (all exercisable) 2,889,066 $35.18  2,889,066 $35.18 
Options granted 662,122 37.75  662,122 37.75 
Converted Allegheny options 1,805,811 41.75  1,805,811 41.75 
Options exercised  (182,422) 29.56   (691,304) 31.38 
Options forfeited/expired  (6,670) 69.36   (78,978) 71.71 
          
Stock options outstanding as of March 31, 2011 5,167,907 $37.96 
Stock options outstanding as of June 30, 2011 4,586,717 $38.09 
          
(4,505,785 options exercisable) 
(3,924,595 options exercisable) 
Compensation expense recognized for stock options during the threesix months ended March 31,June 30, 2011 was $0.1$0.3 million. No expense was recognized during the threesix months ending March 31,ended June 30, 2010. Options granted during the threesix months ended March 31,June 30, 2011 had a grant-date fair value of $3.3 million and an expected weighted-average vesting period of 3.79 years.

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Options outstanding by exercise price as of March 31,June 30, 2011 were as follows:
                        
 Weighted Remaining  Weighted Remaining 
 Shares Under Average Contractual  Shares Under Average Contractual 
Exercise Prices Options Exercise Price Life in Years  Options Exercise Price Life in Years 
 
$20.02 – $30.74 1,305,563 $26.72 2.01  1,045,122 $26.54 2.02 
$30.89 – $40.93 3,378,866 37.22 4.79  3,160,440 37.30 4.17 
$42.72 – $51.82 37,233 44.40 0.24  3,883 51.02 0.70 
$53.06 – $62.97 54,559 56.15 3.27  54,559 56.15 3.02 
$64.52 – $71.82 54,778 68.52 1.09  9,042 67.50 5.24 
$73.39 – $80.47 327,570 80.19 6.01  311,003 80.17 3.81 
$81.19 – $89.59 9,338 83.51 1.92  2,668 85.39 6.09 
              
Total 5,167,907 $37.96 4.07  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 threesix months ended March 31,June 30, 2011 and 2010, net of amounts capitalized, totaled $1$2 million and $(3)$(6) million, respectively. No performance shares under the FirstEnergy LTIP were settled during the threesix months ended March 31,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 threesix months ended March 31,June 30, 2011 and 2010, net of amounts capitalized and dividends on common stock, were $7$19 million and $5$10 million, respectively.
(C) EDCP
CompensationThere was no material compensation expense (income) recognized on EDCP stock units forduring the threesix months ended March 31,June 30, 2011 and 2010, net of amounts capitalized, was not material.2010.
(D) DCPD
DCPD expenses recognized forduring the threesix months ended March 31,June 30, 2011 and 2010 were approximately $1$2 million and $1 million.in each period. The net liability recognized for DCPD of approximately $5$6 million as of March 31,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 March 31,June 30, 2011.

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12. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
DuringIn May 2011, the three months ended March 31,FASB amended authoritative accounting guidance regarding fair value measurement. The amendment prohibits the application of block discounts for all fair value measurements, permits the fair value of certain financial instruments to be measured on the basis of the net risk exposure and allows the application of premiums or discounts to the 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 sensitivity of recurring 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 classification of items whose fair value is not recorded but is disclosed in the notes. The amendment is effective for FirstEnergy in the first quarter of 2012. FirstEnergy does not expect this amendment to have a material effect on its financial statements.
In June 2011, there were nothe FASB issued new accounting standardsguidance 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 interpretations issued,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 that would materially affectfor FirstEnergy in the first quarter of 2012. This amendment will not have a material effect on FirstEnergy’s financial statements.
13. SEGMENT INFORMATION
With the completion of the Allegheny merger in the first quarter of 2011, FirstEnergy reorganized its management structure, which resulted in changes to its operating segments to be consistent with the manner in which management views the business. The new structure supports the combined company’s primary operations — distribution, transmission, generation and the marketing and sale of its products. The external segment reporting is consistent with the internal financial reporting utilizedused 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.

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Prior to the change in composition of business segments, FirstEnergy’s business was comprised of two reportable operating segments. The Energy Delivery Services segment includedwas 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”“Other/Corporate” segment consisted of corporate items and other businesses that were below the quantifiable threshold for separate disclosure. Disclosures for FirstEnergy’s operating segments for 2010 have been reclassified to conform to the current presentation.
The changes in FirstEnergy’s reportable segments during the first quarter of 2011 consisted primarily of the following:
Energy Delivery Services was renamed Regulated Distribution and the operations of MP, PE and WP, which were acquired as part of the merger with Allegheny, and certain regulatory asset recovery mechanisms formerly included in the “Other” segment, were placed into this segment.
A new Regulated Independent Transmission segment was created consisting of ATSI, and the operations of TrAIL Company and FirstEnergy’s interest in PATH; TrAIL and PATH were acquired as part of the merger with Allegheny. The transmission assets and operations of JCP&L, Met-Ed, Penelec, MP, PE and WP remain within the Regulated Distribution segment.
AE Supply, an operator of generation facilities that was acquired as part of the merger with Allegheny, was placed into the Competitive Energy Services segment.
Financial information for each of FirstEnergy’s reportable segments is presented in the table below, which includes financial results for Allegheny beginning February 25, 2011. FES and the Utilities do not have separate reportable operating segments.
The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving approximately 6 million customers within 67,000 square miles of Ohio, Pennsylvania, West Virginia, Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS and default service requirements in Ohio, Pennsylvania, New Jersey and New Jersey.Maryland. This segment also includes the transmission operations of JCP&L, Met-Ed, Penelec, WP, MP and PE and the regulated electric generation facilities in West Virginia and New Jersey which MP and JCP&L, respectively, own or contractually control.
The Regulated Distribution segment’s revenues are primarily derived from the delivery of electricity within FirstEnergy’s service areas, cost recovery of regulatory assets and the sale of electric generation service to retail customers who have not selected an alternative supplier (POLR, SOS or default service) in its Maryland, New Jersey, Ohio and Pennsylvania franchise areas. Its results reflect the commodity costs of securing electric generation from FES and AE Supply and from non-affiliated power suppliers and the deferral and amortization of certain fuel costs.

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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 debt and equityinvestment 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. On June 1, 2011, the ATSI transmission assets currentlypreviously dedicated to MISO are scheduled to bewere integrated into the PJM market. This integration brings allAll of FirstEnergy’s assets intonow 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 20,000 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 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 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
                                                
 Competitive Regulated        Competitive Regulated       
 Regulated Energy Independent Other/ Reconciling    Regulated Energy Independent Other/ Reconciling   
Three Months Ended Distribution Services Transmission Corporate Adjustments Consolidated  Distribution Services Transmission Corporate Adjustments Consolidated 
 (In millions)  (In millions) 
March 31, 2011
 
June 30, 2011
 
External revenues $2,268 $1,254 $67 $(23) $(22) $3,544  $2,485 $1,495 $105 $(30) $(7) $4,048 
Internal revenues — 343 — —  (311) 32  — 318 — —  (306) 12 
                          
Total revenues 2,268 1,597 67  (23)  (333) 3,576  2,485 1,813 105  (30)  (313) 4,060 
Depreciation and amortization 245 88 13 6 — 352  240 107 18 7 — 372 
Investment income (loss), net 25 6 — —  (10) 21  27 15 — 1  (12) 31 
Net interest charges 131 68 9 19  (14) 213  145 67 11 21 1 245 
Income taxes 56 3 7  (20) 32 78  108 7 18  (30)  (2) 101 
Net income (loss) 96 5 13  (35)  (34) 45  184 12 31  (51)  (5) 171 
Total assets 27,165 17,308 2,479 914 — 47,866  26,932 17,146 2,339 1,179 — 47,596 
Total goodwill 5,551 976 — — — 6,527  5,551 905 — — — 6,456 
Property additions 177 214 27 31 — 449  302 197 45 25 — 569 
  
March 31, 2010
 
June 30, 2010
 
External revenues $2,484 $719 $57 $(22) $(6) $3,232  $2,314 $795 $59 $(21) $(8) $3,139 
Internal revenues — 674 — —  (607) 67  19 539 — —  (558) — 
                          
Total revenues 2,484 1,393 57  (22)  (613) 3,299  2,333 1,334 59  (21)  (566) 3,139 
Depreciation and amortization 313 77 12 3 — 405  264 71 13 3 — 351 
Investment income (loss), net 26 1 — 1  (12) 16  28 13 — —  (10) 31 
Net interest charges 124 33 5 13  (3) 172  124 33 5 9  (4) 167 
Income taxes 62 42 7  (12) 12 111  81 75 7  (12)  (17) 134 
Net income (loss) 103 69 12  (19)  (16) 149  132 121 11  (20) 12 256 
Total assets 21,535 10,950 995 598 — 34,078  21,457 11,102 993 914 — 34,466 
Total goodwill 5,551 24 — — — 5,575  5,551 24 — — — 5,575 
Property additions 152 329 14 13 — 508  157 290 15 27 — 489 
 
Six Months Ended
 
 
June 30, 2011
 
External revenues $4,753 $2,736 $172 $(53) $(16) $7,592 
Internal revenues — 661 — —  (617) 44 
             
Total revenues 4,753 3,397 172  (53)  (633) 7,636 
Depreciation and amortization 485 195 31 13 — 724 
Investment income (loss), net 52 21 — 1  (22) 52 
Net interest charges 276 122 20 40 — 458 
Income taxes 164 10 25  (50) 30 179 
Net income (loss) 280 17 44  (86)  (39) 216 
Total assets 26,932 17,146 2,339 1,179 — 47,596 
Total goodwill 5,551 905 — — — 6,456 
Property additions 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 
Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting primarily consist of 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. TwoThe following events described in the sections below occurred during for the first quartersix months of 2011 that indicated the carrying value of certain assets may not be recoverable as described in the sections below.recoverable.

74

Fremont Energy Center
On March 11, 2011, FirstEnergy and American Municipal Power, Inc., (AMP) entered into an agreement for the sale of Fremont Energy Center, which includes two natural gas combined-cycle combustion turbines and a steam turbine capable of producing 544 MW of load-following capacity and 163 MW of peaking capacity. The agreement provides, among other things, for a targeted closing date in July 2011. The execution of this agreement triggered a need to evaluate the recoverability of the carrying value of the assets associated with the Fremont Energy Center. The estimated fair value of the Fremont Energy Center was based on the purchase price outlined in the sale agreement with American Municipal Power, Inc. The result of this evaluation indicated that the carrying cost of the Fremont Energy Center was not fully recoverable. As a result of the recoverability evaluation, FirstEnergy recorded an impairment charge of $11 million to operating income during the quarter ended March 31, 2011. On April 19,July 28, 2011, FGCO filed an section 203 application withFirstEnergy closed the FERC for authorization to sell thesale of Fremont Energy Center including related capacity supply obligations, to AMP. Comments are due on the filing on or before May 10, 2011. FGCO requested FERC action by June 17, 2011.American Municipal Power, Inc.

70

Peaking Facilities
During the threefirst six months ended March 31,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. AsFirstEnergy 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, FirstEnergy recorded an impairment charge of $14 million to the operating income of its Competitive Energy Services segment during the quarter ended March 31, 2011.evaluation.
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 OE includeTE primarily relate to the decommissioning of the Beaver Valley, Davis-Besse and Perry nuclear generating facilities.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 OEPenelec use an expected cash flow approach to measure the fair value of their nuclear decommissioning AROs.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, asrespectively.
During the second quarter of March 31, 2011.2011, 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 revisionrevisions to the estimated cash flows had no significant impact on accretion of the obligation during the first quarter ofthree months and six months ended June 30, 2011 when compared to the first quartersame 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 six month periods ended March 31,June 30, 2011 and 2010, consolidating balance sheets as of March 31,June 30, 2011 and December 31, 2010 and consolidating statements of cash flows for the three months ended March 31,June 30, 2011 and 2010 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.

 

7175

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
                                        
For the Three Months Ended March 31, 2011 FES FGCO NGC Eliminations Consolidated 
For the Three Months Ended June 30, 2011 FES FGCO NGC Eliminations Consolidated 
 (In thousands)  (In millions) 
  
REVENUES
 $1,366,899 $742,638 $467,967 $(1,186,416) $1,391,088  $1,275 $535 $393 $(911) $1,292 
                      
  
EXPENSES:
  
Fuel 1,203 293,862 48,044 — 343,109  6 266 44 — 316 
Purchased power from affiliates 1,184,606 1,772 68,743  (1,186,378) 68,743  902 9 65  (911) 65 
Purchased power from non-affiliates 296,733 205 — — 296,938  332  (3) — — 329 
Other operating expenses 177,529 118,245 188,009 12,152 495,935  159 115 143 12 429 
Provision for depreciation 879 31,539 37,333  (1,299) 68,452  1 32 36  (1) 68 
General taxes 12,263 9,453 7,389 — 29,105  16 8 6 — 30 
Impairment of long-lived assets — 13,800 — — 13,800  — 7 — — 7 
                      
Total expenses 1,673,213 468,876 349,518  (1,175,525) 1,316,082  1,416 434 294  (900) 1,244 
                      
  
OPERATING INCOME (LOSS)
  (306,314) 273,762 118,449  (10,891) 75,006   (141) 101 99  (11) 48 
                      
  
OTHER INCOME (EXPENSE):
  
Investment income 676 232 4,953 — 5,861  — 1 15 — 16 
Miscellaneous income, including net income from equity investees 247,859 584 —  (229,202) 19,241 
Miscellaneous income (expense), including net income from equity investees 123 1 —  (120)  4 
Interest expense — affiliates  (50)  (451)  (516) —  (1,017) —  (1)  (1) —  (2)
Interest expense — other  (24,133)  (27,758)  (16,836) 15,767  (52,960)  (24)  (28)  (16) 16  (52)
Capitalized interest 131 4,826 4,962 — 9,919  — 5 5 — 10 
                      
Total other income (expense) 224,483  (22,567)  (7,437)  (213,435)  (18,956) 99  (22) 3  (104)  (24)
                      
  
INCOME (LOSS) BEFORE INCOME TAXES
  (81,831) 251,195 111,012  (224,326) 56,050   (42) 79 102  (115) 24 
  
INCOME TAXES (BENEFITS)
  (117,841) 93,129 42,374 2,454 20,116   (62) 25 38 3 4 
                      
  
NET INCOME
 36,010 158,066 68,638  (226,780) 35,934  $20 $54 $64 $(118) $20 
            
Loss attributable to noncontrolling interest —  (76) — —  (76)
           
 
EARNINGS AVAILABLE TO PARENT
 $36,010 $158,142 $68,638 $(226,780) $36,010 
           

 

7276

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
                                        
For the Three Months Ended March 31, 2010 FES FGCO NGC Eliminations Consolidated 
For the Six Months Ended June 30, 2011 FES FGCO NGC Eliminations Consolidated 
 (In thousands)  (In millions) 
  
REVENUES
 $1,367,025 $568,364 $426,320 $(973,616) $1,388,093  $2,642 $1,278 $862 $(2,098) $2,684 
                      
  
EXPENSES:
  
Fuel 5,097 280,863 42,261 — 328,221  7 560 92 — 659 
Purchased power from affiliates 968,537 5,079 60,953  (973,616) 60,953  2,087 11 134  (2,098) 134 
Purchased power from non-affiliates 450,216 — — — 450,216  629  (3) — — 626 
Other operating expenses 53,125 99,776 139,420 12,189 304,510  321 233 331 25 910 
Provision for depreciation 790 26,527 36,910  (1,309) 62,918  2 63 74  (3) 136 
General taxes 5,498 14,600 6,648 — 26,746  27 19 14 — 60 
Impairment of long-lived assets — 1,833 — — 1,833 
Impairment charges of long-lived assets — 20 — — 20 
                      
Total expenses 1,483,263 428,678 286,192  (962,736) 1,235,397  3,073 903 645  (2,076) 2,545 
                      
  
OPERATING INCOME (LOSS)
  (116,238) 139,686 140,128  (10,880) 152,696   (431) 375 217  (22) 139 
                      
  
OTHER INCOME (EXPENSE):
  
Investment income (loss) 1,897 54  (1,234) — 717 
Miscellaneous income (expense), including net income from equity investees 166,373 200  (101)  (163,329) 3,143 
Investment income 1 1 20 — 22 
Miscellaneous income, including net income from equity investees 356 2 —  (350) 8 
Interest expense — affiliates  (58)  (1,812)  (435) —  (2,305)  (1)  (1)  (1) —  (3)
Interest expense — other  (23,373)  (26,506)  (15,763) 15,998  (49,644)  (48)  (56)  (33) 32  (105)
Capitalized interest 100 16,333 3,257 — 19,690  — 10 10 — 20 
                      
Total other income (expense) 144,939  (11,731)  (14,276)  (147,331)  (28,399) 308  (44)  (4)  (318)  (58)
                      
  
INCOME BEFORE INCOME TAXES
 28,701 127,955 125,852  (158,211) 124,297 
INCOME (LOSS) BEFORE INCOME TAXES
  (123) 331 213  (340) 81 
  
INCOME TAXES (BENEFITS)
  (51,225) 48,043 45,013 2,540 44,371   (179) 119 80 5 25 
                      
  
NET INCOME
 $79,926 $79,912 $80,839 $(160,751) $79,926  $56 $212 $133 $(345) $56 
                      

 

7377

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
                     
For the Three Months Ended June 30, 2010 FES  FGCO  NGC  Eliminations  Consolidated 
  (In millions) 
                     
REVENUES
 $1,307  $581  $339  $(901) $1,326 
                
                     
EXPENSES:
                    
Fuel  7   302   34   —   343 
Purchased power from affiliates  913   8   49   (901)  69 
Purchased power from non-affiliates  310   —   —   —   310 
Other operating expenses  81   94   117   12   304 
Provision for depreciation  1   27   36   (1)  63 
General taxes  6   9   7   —   22 
                
Total expenses  1,318   440   243   (890)  1,111 
                
                     
OPERATING INCOME (LOSS)
  (11)  141   96   (11)  215 
                
                     
OTHER INCOME (EXPENSE):
                    
Investment income  2   —   11   —   13 
Miscellaneous income, including net income from equity investees  151   1   —   (148)  4 
Interest expense — affiliates  —   (2)  —   —   (2)
Interest expense — other  (24)  (28)  (15)  16   (51)
Capitalized interest  —   20   4   —   24 
                
Total other income (expense)  129   (9)  —   (132)  (12)
                
                     
INCOME BEFORE INCOME TAXES
  118   132   96   (143)  203 
                     
INCOME TAXES (BENEFITS)
  (16)  48   34   3   69 
                
                     
NET INCOME
 $134  $84  $62  $(146) $134 
                

78

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
                     
For the Six Months Ended June 30, 2010 FES  FGCO  NGC  Eliminations  Consolidated 
  (In millions) 
 
REVENUES
 $2,674  $1,149  $765  $(1,874) $2,714 
                
                     
EXPENSES:
                    
Fuel  12   582   77   —   671 
Purchased power from affiliates  1,881   12   111   (1,874)  130 
Purchased power from non-affiliates  760   —   —   —   760 
Other operating expenses  134   194   256   24   608 
Provision for depreciation  2   54   73   (3)  126 
General taxes  11   24   14   —   49 
Impairment of long-lived assets  —   2   —   —   2 
                
Total expenses  2,800   868   531   (1,853)  2,346 
                
                     
OPERATING INCOME (LOSS)
  (126)  281   234   (21)  368 
                
                     
OTHER INCOME (EXPENSE):
                    
Investment income  4   —   10   —   14 
Miscellaneous income, including net income from equity investees  317   1   —   (311)  7 
Interest expense to affiliates  —   (4)  (1)  —   (5)
Interest expense — other  (48)  (54)  (31)  32   (101)
Capitalized interest  —   36   8   —   44 
                
Total other income (expense)  273   (21)  (14)  (279)  (41)
                
                     
INCOME BEFORE INCOME TAXES
  147   260   220   (300)  327 
                     
INCOME TAXES (BENEFITS)
  (67)  97   78   5   113 
                
                     
NET INCOME
 $214  $163  $142  $(305) $214 
                

79

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)
                      
As of March 31, 2011 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 $— $6,831 $8 $— $6,839  $— $6 $— $— $6 
Receivables-  
Customers 388,951 — — — 388,951  450 — — — 450 
Associated companies 621,241 500,097 269,750  (857,808) 533,280  481 425 263  (679) 490 
Other 27,966 7,617 51,128 — 86,711  24 23 4 — 51 
Notes receivable from associated companies 5,742 389,312 83,364 — 478,418  6 410 74 — 490 
Materials and supplies, at average cost 46,747 251,190 191,060 — 488,997  54 253 192 — 499 
Derivatives 328,156 — — — 328,156  221 — — — 221 
Prepayments and other 41,403 9,093 948  (506) 50,938  34 14 1 — 49 
                      
 1,460,206 1,164,140 596,258  (858,314) 2,362,290  1,270 1,131 534  (679) 2,256 
                      
  
PROPERTY, PLANT AND EQUIPMENT:
  
In service 99,899 6,102,623 5,421,719  (384,676) 11,239,565  101 6,105 5,634  (385) 11,455 
Less — Accumulated provision for depreciation 17,918 2,035,726 2,230,588  (176,690) 4,107,542  19 2,067 2,298  (178) 4,206 
                      
 81,981 4,066,897 3,191,131  (207,986) 7,132,023  82 4,038 3,336  (207) 7,249 
Construction work in progress 8,139 147,546 600,620 — 756,305  10 198 486 — 694 
Property, plant and equipment held for sale, net — 476,602 — — 476,602  — 487 — — 487 
                      
 90,120 4,691,045 3,791,751  (207,986) 8,364,930  92 4,723 3,822  (207) 8,430 
                      
  
INVESTMENTS:
  
Nuclear plant decommissioning trusts — — 1,159,903 — 1,159,903  — — 1,184 — 1,184 
Investment in associated companies 5,175,787 — —  (5,175,787) —  5,302 — —  (5,302) — 
Other 371 9,171 202 — 9,744  1 9 — — 10 
                      
 5,176,158 9,171 1,160,105  (5,175,787) 1,169,647  5,303 9 1,184  (5,302) 1,194 
                      
  
DEFERRED CHARGES AND OTHER ASSETS:
  
Accumulated deferred income tax benefits 32,544 376,182 —  (408,726) —  18 344 —  (362) — 
Customer intangibles 131,870 — — — 131,870  129 — — — 129 
Goodwill 24,248 — — — 24,248  24 — — — 24 
Property taxes — 16,463 24,649 — 41,112  — 16 25 — 41 
Unamortized sale and leaseback costs — 23,288 — 67,515 90,803  — 6 — 70 76 
Derivatives 211,223 — — — 211,223  135 — — — 135 
Other 26,661 75,647 8,157  (57,408) 53,057  39 97 7  (68) 75 
                      
 426,546 491,580 32,806  (398,619) 552,313  345 463 32  (360) 480 
                      
 $7,153,030 $6,355,936 $5,580,920 $(6,640,706) $12,449,180  $7,010 $6,326 $5,572 $(6,548) $12,360 
                      
  
LIABILITIES AND CAPITALIZATION
  
 
CURRENT LIABILITIES:
  
Currently payable long-term debt $785 $373,550 $632,106 $(19,578) $986,863  $1 $436 $671 $(20) $1,088 
Short-term borrowings-  
Associated companies 321,133 39,410 — — 360,543  453 88 — — 541 
Other — 661 — — 661  — 1 — — 1 
Accounts payable-  
Associated companies 769,133 290,902 208,889  (768,988) 499,936  665 231 165  (668) 393 
Other 92,874 96,270 — — 189,144  80 111 — — 191 
Accrued taxes 2,721 98,597 65,919  (100,744) 66,493 
Derivatives 380,744 — — — 380,744  242 — — — 242 
Other 31,698 119,402 26,282 47,143 224,525  69 137 46 10 262 
                      
 1,599,088 1,018,792 933,196  (842,167) 2,708,909  1,510 1,004 882  (678) 2,718 
                      
 
CAPITALIZATION:
  
Common stockholder’s equity 3,824,540 2,673,372 2,487,105  (5,160,461) 3,824,556 
Total equity 3,858 2,728 2,556  (5,285) 3,857 
Long-term debt and other long-term obligations 1,488,455 2,113,043 793,250  (1,249,751) 3,144,997  1,483 2,050 706  (1,239) 3,000 
                      
 5,312,995 4,786,415 3,280,355  (6,410,212) 6,969,553  5,341 4,778 3,262  (6,524) 6,857 
                      
  
NONCURRENT LIABILITIES:
  
Deferred gain on sale and leaseback transaction — — — 950,726 950,726  — — — 942 942 
Accumulated deferred income taxes — — 456,556  (339,053) 117,503  — — 504  (288) 216 
Accumulated deferred investment tax credits — 32,511 20,670 53,181 
Asset retirement obligations — 27,114 839,529 — 866,643  — 28 847 — 875 
Retirement benefits 48,818 240,467 — — 289,285  50 245 — — 295 
Property taxes — 16,463 24,649 — 41,112 
Lease market valuation liability — 205,366 — — 205,366  — 194 — — 194 
Derivatives 168,409 — — — 168,409  85 — — — 85 
Other 23,720 28,808 25,965 — 78,493  24 77 77 — 178 
                      
 240,947 550,729 1,367,369 611,673 2,770,718  159 544 1,428 654 2,785 
                      
 $7,153,030 $6,355,936 $5,580,920 $(6,640,706) $12,449,180  $7,010 $6,326 $5,572 $(6,548) $12,360 
                      

 

7480

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)
                      
As of December 31, 2010 FES FGCO NGC Eliminations Consolidated  FES FGCO NGC Eliminations Consolidated 
 (In thousands)  (In millions) 
ASSETS
  
CURRENT ASSETS:
  
Cash and cash equivalents $— $9,273 $8 $— $9,281  $— $9 $— $— $9 
Receivables-  
Customers 365,758 — — — 365,758  366 — — — 366 
Associated companies 333,323 356,564 125,716  (338,038) 477,565  333 357 126  (338) 478 
Other 21,010 55,758 12,782 — 89,550  21 56 13 — 90 
Notes receivable from associated companies 34,331 188,796 173,643 — 396,770  34 189 174 — 397 
Materials and supplies, at average cost 40,713 276,149 228,480 — 545,342  41 276 228 — 545 
Derivatives 181,660 — — — 181,660  182 — — — 182 
Prepayments and other 47,712 11,352 1,107 — 60,171  48 10 1 — 59 
                      
 1,024,507 897,892 541,736  (338,038) 2,126,097  1,025 897 542  (338) 2,126 
                      
  
PROPERTY, PLANT AND EQUIPMENT:
  
In service 96,371 6,197,776 5,411,852  (384,681) 11,321,318  96 6,198 5,412  (385) 11,321 
Less — Accumulated provision for depreciation 17,039 2,020,463 2,162,173  (175,395) 4,024,280  17 2,020 2,162  (175) 4,024 
                      
 79,332 4,177,313 3,249,679  (209,286) 7,297,038  79 4,178 3,250  (210) 7,297 
Construction work in progress 8,809 519,651 534,284 — 1,062,744  9 520 534 — 1,063 
                      
 88,141 4,696,964 3,783,963  (209,286) 8,359,782  88 4,698 3,784  (210) 8,360 
                      
  
INVESTMENTS:
  
Nuclear plant decommissioning trusts — — 1,145,846 — 1,145,846  — — 1,146 — 1,146 
Investment in associated companies 4,941,763 — —  (4,941,763) —  4,942 — —  (4,942) — 
Other 374 11,128 202 — 11,704  — 12 — — 12 
                      
 4,942,137 11,128 1,146,048  (4,941,763) 1,157,550  4,942 12 1,146  (4,942) 1,158 
                      
  
DEFERRED CHARGES AND OTHER ASSETS:
  
Accumulated deferred income tax benefits 42,986 412,427 —  (455,413) —  43 412 —  (455) — 
Customer intangibles 133,968 — — — 133,968  134 — — — 134 
Goodwill 24,248 — — — 24,248  24 — — — 24 
Property taxes — 16,463 24,649 — 41,112  — 16 25 — 41 
Unamortized sale and leaseback costs — 10,828 — 62,558 73,386  — 10 — 63 73 
Derivatives 97,603 — — — 97,603  98 — — — 98 
Other 21,018 70,810 14,463  (57,602) 48,689  21 71 14  (58) 48 
                      
 319,823 510,528 39,112  (450,457) 419,006  320 509 39  (450) 418 
                      
 $6,374,608 $6,116,512 $5,510,859 $(5,939,544) $12,062,435  $6,375 $6,116 $5,511 $(5,940) $12,062 
                      
  
LIABILITIES AND CAPITALIZATION
  
 
CURRENT LIABILITIES:
  
Currently payable long-term debt $100,775 $418,832 $632,106 $(19,578) $1,132,135  $101 $419 $632 $(20) $1,132 
Short-term borrowings-  
Associated companies — 11,561 — — 11,561  — 12 — — 12 
Other — — — — — 
Accounts payable-  
Associated companies 351,172 212,620 249,820  (346,989) 466,623  351 213 250  (347) 467 
Other 139,037 102,154 — — 241,191  139 102 — — 241 
Accrued taxes 3,358 36,187 30,726  (142) 70,129 
Derivatives 266,411 — — — 266,411  266 — — — 266 
Other 51,619 147,754 15,156 37,142 251,671  56 183 46 37 322 
                      
 912,372 929,108 927,808  (329,567) 2,439,721  913 929 928  (330) 2,440 
                      
  
CAPITALIZATION:
  
Common stockholder’s equity 3,788,245 2,514,775 2,413,580  (4,928,859) 3,787,741  3,788 2,515 2,414  (4,929) 3,788 
Long-term debt and other long-term obligations 1,518,586 2,118,791 793,250  (1,249,752) 3,180,875  1,519 2,119 793  (1,250) 3,181 
                      
 5,306,831 4,633,566 3,206,830  (6,178,611) 6,968,616  5,307 4,634 3,207  (6,179) 6,969 
                      
  
NONCURRENT LIABILITIES:
  
Deferred gain on sale and leaseback transaction — — — 959,154 959,154  — — — 959 959 
Accumulated deferred income taxes — — 448,115  (390,520) 57,595  — — 448  (390) 58 
Accumulated deferred investment tax credits — 33,280 20,944 — 54,224 
Asset retirement obligations — 26,780 865,271 — 892,051  — 27 865 — 892 
Retirement benefits 48,214 236,946 — — 285,160  48 237 — — 285 
Property taxes — 16,463 24,649 — 41,112 
Lease market valuation liability — 216,695 — — 216,695  — 217 — — 217 
Derivatives 81,393 — — — 81,393  81 — — — 81 
Other 25,798 23,674 17,242 — 66,714  26 72 63 — 161 
                      
 155,405 553,838 1,376,221 568,634 2,654,098  155 553 1,376 569 2,653 
                      
 $6,374,608 $6,116,512 $5,510,859 $(5,939,544) $12,062,435  $6,375 $6,116 $5,511 $(5,940) $12,062 
                      

 

7581

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
                               
For the Three Months Ended March 31, 2011 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
 $(215,124) $267,047 $41,702 $— $93,625  $(329) $321 $200 $(10) $182 
                      
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New Financing-  
Long-term debt — 90,190 60,000 — 150,190  — 140 107 — 247 
Short-term borrowings, net 321,134 28,509 — — 349,643  453 77 — — 530 
Redemptions and Repayments-  
Long-term debt  (130,208)  (141,220)  (60,000) —  (331,428)  (135)  (192)  (155) 10  (472)
Other  (430)  (222)  (365) —  (1,017)  (9)  (1)  (1) —  (11)
                      
Net cash provided from (used for) financing activities 190,496  (22,743)  (365) — 167,388  309 24  (49) 10 294 
                      
  
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (2,858)  (39,791)  (116,357) —  (159,006)  (6)  (109)  (219) —  (334)
Sales of investment securities held in trusts — — 215,620 — 215,620  — — 513 — 513 
Purchases of investment securities held in trusts — —  (230,912) —  (230,912) — —  (545) —  (545)
Loans from (to) associated companies, net 28,589  (200,516) 90,280 —  (81,647)
Loans to associated companies, net 28  (221) 100 —  (93)
Customer acquisition costs  (1,103) — — —  (1,103)  (2) — — —  (2)
Other —  (6,439) 32 —  (6,407) —  (18) — —  (18)
                      
Net cash provided from (used for) investing activities 24,628  (246,746)  (41,337) —  (263,455) 20  (348)  (151) —  (479)
                      
  
Net change in cash and cash equivalents —  (2,442) — —  (2,442) —  (3) — —  (3)
Cash and cash equivalents at beginning of period — 9,273 8 — 9,281  — 9 — — 9 
                      
Cash and cash equivalents at end of period $— $6,831 $8 $— $6,839  $— $6 $— $— $6 
                      

 

7682

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
                               
For the Three Months Ended March 31, 2010 FES FGCO NGC Eliminations Consolidated 
 (In thousands) 
For the Six Months Ended June 30, 2010 FES FGCO NGC Eliminations Consolidated 
  (In millions) 
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES
 $(147,718) $40,130 $98,692 $— $(8,896) $(223) $163 $287 $(9) $218 
                      
  
CASH FLOWS FROM FINANCING ACTIVITIES:
  
New Financing- 
Short-term borrowings, net — 76 — — 76 
Redemptions and Repayments-  
Long-term debt  (197)  (1,081) — —  (1,278) —  (261)  (43) 9  (295)
Short-term borrowings, net —  (9,237) — —  (9,237)
Other  (453)  (177)  (101) —  (731)  (1) — — —  (1)
                      
Net cash used for financing activities  (650)  (10,495)  (101) —  (11,246)  (1)  (185)  (43) 9  (220)
                      
 
CASH FLOWS FROM INVESTING ACTIVITIES:
  
Property additions  (2,103)  (174,163)  (125,337) —  (301,603)  (4)  (333)  (229) —  (566)
Proceeds from asset sales — 114,272 — — 114,272  — 116 — — 116 
Sales of investment securities held in trusts — — 272,094 — 272,094  — — 957 — 957 
Purchases of investment securities held in trusts — —  (284,888) —  (284,888) — —  (979) —  (979)
Loans from associated companies, net 250,908 31,232 39,540 — 321,680 
Loans to associated companies, net 332 241 58 — 631 
Customer acquisition costs  (100,615) — — —  (100,615)  (105) — — —  (105)
Leasehold improvement payments to associated companies — —  (51) —  (51)
Other 178  (977) — —  (799) 1  (2) — —  (1)
                      
Net cash provided from (used for) investing activities 148,368  (29,636)  (98,591) — 20,141  224 22  (244) — 2 
                      
 
Net change in cash and cash equivalents —  (1) — —  (1) — — — — — 
Cash and cash equivalents at beginning of period — 3 9 — 12  — — — — — 
                      
Cash and cash equivalents at end of period $— $2 $9 $— $11  $— $— $— $— $— 
                      

 

7783

Item 2. 
Management’s Discussion and Analysis of Registrant and Subsidiaries
FIRSTENERGY CORP.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS
EXECUTIVE SUMMARY
Earnings available to FirstEnergy Corp. in the first quarter of 2011 were $50$181 million, or basic and diluted earnings of $0.15$0.43 per share of common stock, compared with $155$265 million, or basic and diluted earnings of $0.51$0.87 per share of common stock in the second quarter of 2010. Earnings available to FirstEnergy Corp. in the first six months of 2011 were $231 million or basic and diluted earnings of $0.61 per share of common stock, compared with $420 million or basic earnings of $1.38 ($1.37 diluted) per share of common stock in the first quartersix months of 2010. The principal reasons for the decreases are summarized below.
     
Change in Basic Earnings Per Share From Prior Year 2011 
     
Basic earnings Per Share — First Quarter 2010 $0.51 
Non-core asset sales/impairments  (0.03)
Trust securities impairments  0.01 
Mark-to-market adjustments  0.09 
Income tax charge from healthcare legislation — 2010  0.04 
Regulatory charges — 2011  (0.04)
Regulatory charges — 2010  0.08 
Merger-related costs  (0.34)
Revenues  (0.26)
Fuel and purchased power  0.21 
Transmission expense  (0.07)
Amortization of regulatory assets, net  0.07 
Interest expense  0.03 
Merger accounting — commodity contracts  (0.04)
Allegheny earnings contribution*  0.13 
Additional shares issued  (0.06)
Other  (0.18)
    
Basic earnings Per Share — First Quarter 2011 $0.15 
    
         
  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.separately
Merger
On February 25, 2011, the merger between FirstEnergy and Allegheny closed. Pursuant to the terms of the Agreement and Plan of Merger between 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 a wholly-owned subsidiary of FirstEnergy. As part of the merger, AE shareholders received 0.667 of a share of FirstEnergy common stock for each AE share outstanding as of the merger completion date and all outstanding AE equity-based employee compensation awards were converted into FirstEnergy equity-based awards on the same basis.
In connection with the merger, FirstEnergy recorded approximately $82$7 million of merger transaction costs during each of the second quarter of 2011 and 2010, and approximately $89 million and $14$21 million of merger transaction costs during the first quartersix 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, induring the three months ended March 31,June 30, 2011, $75$10 million of pre-tax merger integration costs and $24$8 million of charges from merger settlements approved by regulatory agencies have beenwere recognized. In the first 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 2011 merger benefits target resulting from the merger with Allegheny. Through June 2011, FirstEnergy has taken actions and completed savings initiatives that will allow the company to capture merger benefits of approximately $132 million pre-tax on an annual basis, or 63% of the $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.

 

7884

Operational Matters
TrAIL
On May 19, 2011, TrAIL’s 500-kV transmission line, spanning more than 150 miles from southwestern Pennsylvania through West Virginia to northern Virginia, was completed and energized.
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 emergency at the plant and allow for improved coordination between the plant, state and local emergency management agencies. FENOC is expected to break ground for a similar facility for the Davis-Besse Nuclear Power Station in August 2011.
Fremont Energy Center
On March 14,July 28, 2011, FirstEnergy entered into a definitive agreement to sellclosed on the previously announced sale of Fremont Energy Center (707 MW) to American Municipal Power, Inc. (AMP). Under the terms of the agreement, AMP will purchase Fremont Energy Center for approximately $485$510 million based on 685 MW of output. The purchase price wouldcan be incrementally increased, not to exceed an additional $16 million, to reflect additional output and transmission export capacity up to its nameplate capacity of 707 MW. In addition, AMP would reimburse FirstEnergy up to $25.3 million for construction costs incurred from February 1, 2011 through the closing date. On April 19, 2011, FGCO filed an application with the FERC for authorization to sell the Fremont Energy Center, including related capacity supply obligations, to AMP. The transaction is expected to close in July 2011.
Perry Refueling
FENOC shutdown the Perry Nuclear Plant on April 18, 2011, for scheduled refueling and maintenance. During the outage 284 of the 748 fuel assemblies will be exchanged and maintenance safety inspections will be conducted while the unit is off line. Preventative maintenance to ensure continued safe and reliable operations will be preformed, including replacing several control rod blades, rewinding the generator and testing more than 100 valves. On April 25, 2011, the NRC began a Special Inspection to review the circumstances surrounding work activities to remove a source range monitor from the reactor core on April 22, 2011.
Beaver Valley Refueling
On April 11, 2011, FENOC announced that Beaver Valley Unit 2 (911 MW) returned to service following a March 7, 2011 shutdown for refueling and maintenance. During the outage 60 of the 157 fuel assemblies were exchanged, safety inspections were conducted, and numerous maintenance and improvement projects were completed.
Seneca Plant Maintenance
In March 2011, FirstEnergy announced that the Seneca Pumped-Storage Hydroelectric facility (451 MW) will repave its Upper Reservoir, overhaul the shutoff valves and perform routine maintenance activities.
TrAIL
On April 15, 2011, the TrAIL 500 kV line segment from Meadowbrook substation to Loudoun substation in Virginia was successfully energized and is carrying load. The other segments are planned to be energized in May. The entire TrAIL line is scheduled to be completed and placed in service no later than June 2011.
Signal Peak
On March 16, 2011, Signal Peak Energy received a letter from the MSHA indicating that its mine is no longer being considered for a pattern of potential violations notice.
Financial Matters
On March 16,April 29, 2011, PenelecMet-Ed redeemed $13.69 million of pollution control revenue bonds at par value.
On May 4, 2011, AE terminated its $250 million credit facility due to other available funding sources following completion of the merger with FirstEnergy.
On May 31, 2011, JCP&L and Met-Ed extendedrepurchased $500 million and $150 million, respectively, of their equity from FirstEnergy to maintain an appropriate capital structure.
On June 1, 2011, FGCO repurchased $40 million of pollution control revenue bonds and is holding those bonds for three yearsfuture 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 terminated.
On July 29, 2011, FGCO and NGC provided notice to the LOCs supporting two seriestrustee for $158.1 million and $158.9 million, respectively, of PCRBs of their election to terminate applicable supporting LOCs. As a result, these PCRBs are subject to mandatory purchase on September 1, 2011. Subject to market conditions and other considerations, FGCO and NGC currently outstanding in a variable interest rate mode totaling $49 million.
On March 17expect to hold the bonds for future remarketing or refinancing. Also, approximately $28.5 million and April 1, 2011, FES and Penelec completed the remarketing of six series of PCRBs totaling $328 million. Each of these series either remained in or was converted to a variable interest rate mode supported by a three-year bank LOC. In connection with the remarketings, approximately $207$98.9 million aggregate principal amount of FMBs previously delivered to certain of the LOC providers wereby FGCO and NGC, respectively, will be cancelled and approximately $50 million aggregate principal amount of FMBs previously delivered to secure PCRBs are expectedin connection with the mandatory purchases.
Regulatory Matters
NYSEG Ruling
On July 11, 2011, FirstEnergy was found to be cancelled on May 31,a potentially responsible party under CERCLA indirectly liable for a portion of past and future clean-up costs at certain legacy MGP sites in New York. As a result, FirstEnergy recognized additional expense of $29 million during the second quarter of 2011; $30 million had previously been reserved prior to 2011.
On March 29, 2011, FES repaid a $100 million two-year term loan facility secured by FMBs that was scheduled to mature March 31, 2011. On April 8, 2011, FirstEnergy entered into a new $150 million unsecured term loan with an April 2013 maturity.

 

7985

Regulatory Matters
Ohio Energy Efficiency (EE) and Peak Demand Reduction (DR) Portfolio PlanMarginal transmission loss recovery
On March 23,3, 2010, the PPUC issued an order denying Met-Ed and Penelec the ability to recover marginal transmission losses through the transmission service charge riders in their respective tariffs which applies to the periods including June 1, 2008 through December 31, 2010. Subsequently, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania (Commonwealth Court) appealing the PPUC’s order. On June 14, 2011, the PUCO approvedCommonwealth Court affirmed the three-year EEPPUC’s decision that marginal transmission losses are not recoverable as transmission costs. On July 13, 2011, Met-Ed and DR portfolio planPenelec filed a federal complaint with the United States District Court for the Ohio Companies. The Ohio Companies’ plan was developedEastern District of Pennsylvania and on the following day, filed a Petition for Allowance of Appeal to complythe 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 EE mandate in Ohio’s SB 221, passed in 2008. This law requires that utilities in Ohio reduce energy usage by 22.2 percent by 2025related regulatory assets ($189 million for Met-Ed and peak demand by 7.75 percent by 2018, develop$65 million for Penelec). In January 2011 and continuing for 29 months, pursuant to a portfolio plan,related PPUC order, Met-Ed and meet annual benchmarks to measure progress.
Penn SREC
On March 11, 2011,Penelec began crediting customers for the PPUC approved the resultsamounts at issue pending outcome of the Penn procurement of SRECs to meet Pennsylvania’s Alternative Energy Portfolio Standards through 2020. One SREC represents the solar renewable energy attributes of one MWH of generation from a solar generating facility. Penn contracted for 19,800 SREC’s. This purchase of SRECs is equivalent to approximately 2,200 MWH of solar power generation annually over the next nine years. The average cost is $199.09 per SREC, with deliveries scheduled for June 2011 through May 2020.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 consistent with the manner in which management views the business. The new structure supports the combined company’s primary operations — distribution, transmission, generation and the marketing and sale of its products. The external segment reporting is consistent with the internal financial reporting utilizedused 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 included FirstEnergy’s then eight existing utility operating companies that transmit and distribute electricity to customers and purchase power to serve their POLR and default service requirements. The Competitive Energy Services segment was comprised of FES, which supplies electric power to end-use customers through retail and wholesale arrangements. The “Other” segment consisted of corporate items and other businesses that were below the quantifiable threshold for separate disclosure. Disclosures for FirstEnergy’s operating segments for 2010 have been reclassified to conform to the current presentation.
The changes in FirstEnergy’s reportable segments during the first quarter of 2011 consisted primarily of the following:
Energy Delivery Services was renamed Regulated Distribution and the operations of MP, PE and WP, which were acquired as part of the merger with Allegheny, and certain regulatory asset recovery mechanisms formerly included in the “Other” segment, were placed into this segment.
A new Regulated Independent Transmission segment was created consisting of ATSI, and the operations of TrAIL Company and FirstEnergy’s interest in PATH; TrAIL and PATH were acquired as part of the merger with Allegheny. The transmission assets and operations of JCP&L, Met-Ed, Penelec, MP, PE and WP remain within the Regulated Distribution segment.
AE Supply, an operator of generation facilities that was acquired as part of the merger with Allegheny, was placed into the Competitive Energy Services segment.
Financial information for each of FirstEnergy’s reportable segments is presented in the table below, which includes financial results for the Allegheny subsidiaries beginning February 25, 2011. FES and the Utilities do not have separate reportable operating segments.

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The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving approximately 6 million customers within 67,000 square miles of Ohio, Pennsylvania, West Virginia, Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS and default service requirements in Ohio, Pennsylvania, New Jersey and New Jersey.Maryland. This segment also includes the transmission operations of JCP&L, Met-Ed, Penelec, WP, MP and PE and the regulated electric generation facilities in West Virginia and New Jersey which MP and JCP&L, respectively, own or contractually control.
The Regulated Distribution segment’s revenues are primarily derived from the delivery of electricity within FirstEnergy’s service areas, cost recovery of regulatory assets and the sale of electric generation service to retail customers who have not selected an alternative supplier (POLR, SOS or default service) in its Maryland, New Jersey, Ohio and Pennsylvania franchise areas. Its results reflect the commodity costs of securing electric generation from FES and AE Supply and from non-affiliated power suppliers and the deferral and amortization of certain fuel costs.

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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 debt and equityinvestment 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. On June 1, 2011, the ATSI transmission assets currentlypreviously dedicated to MISO are scheduled to bewere integrated into the PJM market. This integration brings allAll of FirstEnergy’s assets intonow 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 20,000 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 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 Other and Reconciling Adjustments segment contains corporate items and other businesses that are below the quantifiable threshold for separate disclosure as a reportable segment.segment as well as reconciling adjustments for the elimination of intersegment transactions.

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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 13 to the consolidated financial statements. Earnings available to FirstEnergy by major business segment were as follows:
                                    
 Three Months Ended    Three Months Ended Six Months Ended 
 March 31 Increase  June 30 June 30 
 2011 2010 (Decrease)  Increase Increase 
 (In millions, except per share data)  2011 2010 (Decrease) 2011 2010 (Decrease) 
Earnings By Business Segment:
 
 (In millions, except per share data) 
Earnings (Loss) By Business Segment:
 
Regulated Distribution $96 $103 $(7) $184 $132 $52 $280 $235 $45 
Competitive Energy Services 5 69  (64) 12 121  (109) 17 190  (173)
Regulated Independent Transmission 13 12 1  31 11 20 44 23 21 
Other and reconciling adjustments*  (64)  (29)  (35)  (46) 1  (47)  (110)  (28)  (82)
                    
Total $50 $155 $(105)
Earnings available to FirstEnergy Corp. $181 $265 $(84) $231 $420 $(189)
                    
  
Basic Earnings Per Share
 $0.15 $0.51 $(0.36) $0.43 $0.87 $(0.44) $0.61 $1.38 $(0.77)
Diluted Earnings Per Share
 $0.15 $0.51 $(0.36) $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.

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Summary of Results of Operations — FirstSecond Quarter 2011 Compared with FirstSecond Quarter 2010
Financial results for FirstEnergy’s major business segments in the firstsecond quarter of 2011 and 2010 were as follows:
                                        
 Competitive Regulated Other and    Competitive Regulated Other and   
 Regulated Energy Independent Reconciling FirstEnergy  Regulated Energy Independent Reconciling FirstEnergy 
First Quarter 2011 Financial Results Distribution Services Transmission Adjustments Consolidated 
Second Quarter 2011 Financial Results Distribution Services Transmission Adjustments Consolidated 
 (In millions)  (In millions) 
Revenues:  
External  
Electric $2,175 $1,162 $— $— $3,337  $2,352 $1,394 $— $— $3,746 
Other 93 92 67  (45) 207  133 101 105  (37) 302 
Internal — 343 —  (311) 32  — 318 —  (306) 12 
                      
Total Revenues 2,268 1,597 67  (356) 3,576  2,485 1,813 105  (343) 4,060 
                      
  
Expenses:  
Fuel 24 429 — — 453  73 562 — — 635 
Purchased power 1,179 318 —  (311) 1,186  1,144 382 —  (306) 1,220 
Other operating expenses 386 648 17  (18) 1,033  438 640 19 8 1,105 
Provision for depreciation 116 88 10 6 220  153 107 15 7 282 
Amortization of regulatory assets 129 — 3 — 132  87 — 3 — 90 
Deferral of new regulatory assets — — — — — 
General taxes 176 44 8 9 237  180 51 8 3 242 
Impairment of long-lived assets — — — — — 
                      
Total Expenses 2,010 1,527 38  (314) 3,261  2,075 1,742 45  (288) 3,574 
                      
  
Operating Income 258 70 29  (42) 315  410 71 60  (55) 486 
                      
Other Income (Expense):  
Investment income 25 6 —  (10) 21  27 15 —  (11) 31 
Interest expense  (132)  (78)  (9)  (12)  (231)  (148)  (79)  (12)  (26)  (265)
Capitalized interest 1 10 — 7 18  3 12 1 4 20 
                      
Total Other Expense  (106)  (62)  (9)  (15)  (192)  (118)  (52)  (11)  (33)  (214)
                      
  
Income Before Income Taxes 152 8 20  (57) 123  292 19 49  (88) 272 
Income taxes 56 3 7 12 78  108 7 18  (32) 101 
                      
Net Income (Loss) 96 5 13  (69) 45  184 12 31  (56) 171 
Loss attributable to noncontrolling interest — — —  (5)  (5) — — —  (10)  (10)
                      
Earnings available to FirstEnergy Corp. $96 $5 $13 $(64) $50 
Earnings (loss) available to FirstEnergy Corp. $184 $12 $31 $(46) $181 
                      

 

8288

                                        
 Competitive Regulated Other and    Competitive Regulated Other and   
 Regulated Energy Independent Reconciling FirstEnergy  Regulated Energy Independent Reconciling FirstEnergy 
First Quarter 2010 Financial Results Distribution Services Transmission Adjustments Consolidated 
Second Quarter 2010 Financial Results Distribution Services Transmission Adjustments Consolidated 
 (In millions)  (In millions) 
Revenues:  
External  
Electric $2,398 $669 $— $— $3,067  $2,243 $739 $— $— $2,982 
Other 86 50 57  (28) 165  71 56 59  (29) 157 
Internal — 674 —  (607) 67  19 539 —  (558) — 
                      
Total Revenues 2,484 1,393 57  (635) 3,299  2,333 1,334 59  (587) 3,139 
                      
  
Expenses:  
Fuel — 334 — — 334  — 350 — — 350 
Purchased power 1,395 450 —  (607) 1,238  1,291 330 —  (558) 1,063 
Other operating expenses 359 352 14  (24) 701  331 340 16  (14) 673 
Provision for depreciation 104 77 9 3 193  106 71 10 3 190 
Amortization of regulatory assets 209 — 3 — 212  158 — 3 — 161 
Deferral of new regulatory assets — — — — — 
General taxes 154 37 7 7 205  138 27 7 4 176 
Impairment of long-lived assets — — — — — 
                      
Total Expenses 2,221 1,250 33  (621) 2,883  2,024 1,118 36  (565) 2,613 
                      
  
Operating Income 263 143 24  (14) 416  309 216 23  (22) 526 
                      
Other Income (Expense):  
Investment income 26 1 —  (11) 16  28 13 —  (10) 31 
Interest expense  (125)  (56)  (5)  (27)  (213)  (125)  (57)  (6)  (19)  (207)
Capitalized interest 1 23 — 17 41  1 24 1 14 40 
                      
Total Other Expense  (98)  (32)  (5)  (21)  (156)  (96)  (20)  (5)  (15)  (136)
                      
  
Income Before Income Taxes 165 111 19  (35) 260  213 196 18  (37) 390 
Income taxes 62 42 7 — 111  81 75 7  (29) 134 
                      
Net Income (Loss) 103 69 12  (35) 149  132 121 11  (8) 256 
Loss attributable to noncontrolling interest — — —  (6)  (6) — — —  (9)  (9)
                      
Earnings available to FirstEnergy Corp. $103 $69 $12 $(29) $155  $132 $121 $11 $1 $265 
                      

 

8389

                                        
Changes Between First Quarter 2011 Competitive Regulated Other and   
and First Quarter 2010 Financial Regulated Energy Independent Reconciling FirstEnergy 
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  Distribution Services Transmission Adjustment Consolidated 
 (In millions) 
 (In millions)  
Revenues:  
External  
Electric $(223) $493 $— $— $270  $109 $655 $— $— $764 
Other 7 42 10  (17) 42  62 45 46  (8) 145 
Internal —  (331) — 296  (35)  (19)  (221) — 252 12 
                      
Total Revenues  (216) 204 10 279 277  152 479 46 244 921 
                      
  
Expenses:  
Fuel 24 95 — — 119  73 212 — — 285 
Purchased power  (216)  (132) — 296  (52)  (147) 52 — 252 157 
Other operating expenses 27 296 3 6 332  107 300 3 22 432 
Provision for depreciation 12 11 1 3 27  47 36 5 4 92 
Amortization of regulatory assets  (80) — — —  (80)  (71) — — —  (71)
Deferral of new regulatory assets — — — — — 
General taxes 22 7 1 2 32  42 24 1  (1) 66 
Impairment of long-lived assets — — — — — 
                      
Total Expenses  (211) 277 5 307 378  51 624 9 277 961 
                      
  
Operating Income  (5)  (73) 5  (28)  (101) 101  (145) 37  (33)  (40)
                      
Other Income (Expense):  
Investment income  (1) 5 — 1 5   (1) 2 —  (1) — 
Interest expense  (7)  (22)  (4) 15  (18)  (23)  (22)  (6)  (7)  (58)
Capitalized interest —  (13) —  (10)  (23) 2  (12) —  (10)  (20)
                      
Total Other Expense  (8)  (30)  (4) 6  (36)  (22)  (32)  (6)  (18)  (78)
                      
  
Income Before Income Taxes  (13)  (103) 1  (22)  (137) 79  (177) 31  (51)  (118)
Income taxes  (6)  (39) — 12  (33) 27  (68) 11  (3)  (33)
                      
Net Income (Loss)  (7)  (64) 1  (34)  (104)
Net Income 52  (109) 20  (48)  (85)
Loss attributable to noncontrolling interest — — — 1 1  — — —  (1)  (1)
                      
Earnings available to FirstEnergy Corp. $(7) $(64) $1 $(35) $(105) $52 $(109) $20 $(47) $(84)
                      
Regulated Distribution — FirstSecond Quarter 2011 Compared with FirstSecond Quarter 2010
Net income decreasedincreased by $7$52 million in the firstsecond quarter of 2011 compared to the firstsecond quarter of 2010 primarily due to lower generation and transmission revenues and merger-related costs associated withearnings from the Allegheny merger,companies and increased operating margins from the pre-merger companies as a result of reduced purchased power costs, partially offset by lower purchased power costs and amortization of regulatory assets.reduced revenues.

 

8490

Revenues —
The decreaseincrease in total revenues resulted from the following sources:
                        
 Three Months    Three Months   
 Ended March 31 Increase  Ended June 30 Increase 
Revenues by Type of Service 2011 2010 (Decrease)  2011 2010 (Decrease) 
 (In millions)  (In millions) 
Pre-merger companies
 
Pre-merger companies: 
Distribution services $909 $883 $26  $810 $851 $(41)
              
Generation sales:  
Retail 873 1,178  (305) 747 1,097  (350)
Wholesale 116 217  (101) 104 180  (76)
              
Total generation sales 989 1,395  (406) 851 1,277  (426)
              
Transmission 37 160  (123) 51 141  (90)
Other 58 46 12  66 64 2 
              
Total pre-merger companies 1,993 2,484  (491) 1,778 2,333  (555)
              
Allegheny companies 275 — 275  707 — 707 
              
Total Revenues $2,268 $2,484 $(216) $2,485 $2,333 $152 
              
The increasedecrease in distribution service revenues reflected higher distribution deliveries infor the first quarter of 2011 comparedpre-merger companies reflects lower transition revenues due to the same periodcompletion of transition cost recovery for CEI in 2010.December 2010, partially offset by increased rates associated with the recovery of deferred distribution costs. Distribution deliveries (excluding the Allegheny companies) increased 650,000 MWH (2.4%) to 27,538,000 MWHdecreased by 1.1% in the firstsecond quarter of 2011 from 26,888,000 MWH in the firstsecond quarter of 2010. The increasechange in distribution deliveries by customer class is summarized in the following table:
                        
 Increase  Increase 
Electric Distribution KWH Deliveries 2011 2010 (Decrease)  2011 2010 (Decrease) 
 (in thousands)  (in thousands) 
 
Pre-merger companies
 
Pre-merger companies: 
Residential 10,638 10,455  1.8% 8,623 8,663  (0.5)%
Commercial 7,929 7,953  (0.3)% 7,926 8,121  (2.4)%
Industrial 8,841 8,351  5.9% 8,798 8,846  (0.5)%
Other 130 129  0.8% 126 132  (4.5)%
              
Total pre-merger companies 27,538 26,888  2.4% 25,473 25,762  (1.1)%
              
Allegheny companies 3,540 — —  9,527 — — 
              
Total Electric Distribution MWH Deliveries 31,078 26,888  15.6%
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 firstsecond quarter of 2011 as heatingcooling degree days increaseddecreased by 5.2%17.3% from the same period in 2010. 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 first quarter of 2010.commercial sector. In the industrial sector, KWH deliveries decreased by 4% to automotive customers, partially offset by increased by 12.8%deliveries to major steel and electrical equipment customers 4.7% to refinery customersof 11% and 8.4% to chemical customers.15%, respectively.
The following table summarizes the price and volume factors contributing to the $406$426 million decrease in generation revenues for the pre-merger companies in the firstsecond quarter of 2011 compared to the firstsecond quarter of 2010:
        
 Increase  Increase 
Source of Change in Generation Revenues (Decrease)  (Decrease) 
 (In millions)  (In millions) 
  
Retail:  
Effect of 32.4% decrease in sales volumes $(382)
Effect of decrease in sales volumes $(447)
Change in prices 77  96 
      
  (305)  (351)
      
Wholesale:  
Effect of 3.9% increase in sales volumes 8 
Effect of decrease in sales volumes  (8)
Change in prices  (109)  (67)
      
  (101)  (75)
      
Net Decrease in Generation Revenues $(406) $(426)
      

 

8591

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 of the pre-merger companies in the firstsecond quarter of 2011, compared towith the firstsecond quarter of 2010. Total generation provided by alternative suppliers as a percentage of total KWH deliveries increased to 73%77% from 53%61% for the Ohio Companiescompanies and to 40%55% from 2% in10% for Met-Ed’s and Penelec’s service areas.
The decrease in wholesale generation revenues reflected lower RPM revenues for Met-Ed and Penelec in the PJM market. Transmission revenues decreased $123$90 million due to the termination of Met-Ed’s and Penelec’s transmission tariffTSC 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 $275$707 million inof revenues for the firstsecond quarter of 2011, including $69$155 million for distribution services, $190$486 million for generation sales and $16$66 million relating to PJM transmission revenues.
Expenses —
Total expenses decreasedincreased by $140$51 million due to the following:
Purchased power costs, excluding the Allegheny companies, were $356$483 million lower in the firstsecond quarter of 2011 due primarily to a decrease in sales volume requirements.volumes required. The decrease in power purchased from FES reflected the increase in customer shopping 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 $140$336 million in purchased power costs in the firstsecond quarter of 2011.
        
 Increase  Increase 
Source of Change in Purchased Power (Decrease)  (Decrease) 
 (In millions)  (In millions) 
Pre-merger companies
 
Pre-merger companies: 
Purchases from non-affiliates:  
Change due to decreased unit costs $(186) $(161)
Change due to increased volumes 188  88 
      
 2   (73)
      
Purchases from FES:  
Change due to increased unit costs 36  20 
Change due to decreased volumes  (412)  (398)
      
  (376)  (378)
      
  
Decrease in costs deferred 18 
Increase in costs deferred  (32)
      
Total pre-merger companies  (356)  (483)
      
Purchases by Allegheny companies 140  336 
      
Net Decrease in Purchased Power Costs $(216) $(147)
      
Transmission expenses decreased $98$29 million primarily due to lower PJM network transmission expenses and congestion costs of $110$70 million for Met-Ed and Penelec, partially offset by transmission expenses for the Allegheny companies of $12$41 million in the firstsecond 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 earnings.
Energy Efficiency program costs, which are also recovered through rates, increased $16by $43 million.
MaterialThe 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.
•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.

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Merger-related costs associated with maintenance activities increased $10$4 million in the firstsecond quarter of 2011 compared to the same period last year.
A provision for excess and obsolete material of $13 million was recognized in the first quarter of 2011 relating to revised inventory practices adopted in conjunction with the Allegheny merger.
Depreciation expense increased $12 million due to property additions since the first quarter of 2010.

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Net amortization of regulatory assets decreased $80 million due primarily to generation-related rate deferrals for the Ohio Companies, Met-Ed and Penelec and reduced net PJM transmission cost amortization.
General taxes increased $22$42 million primarily due to higher property taxes and gross receipts taxes in the first quarter of 2011.
Fuel expenses for MP were $24 million in the first quarter of 2011.         
Operating expenses for the Allegheny companies were $38 million in the first quarter of 2011.
Merger-related costs incurred by the Allegheny companies were $48 million in the firstsecond quarter of 2011.
Other Expense —
Other expense increased $8$22 million in the firstsecond quarter of 2011 due to interest expense on debt of the Allegheny companies.
Regulated Independent Transmission — FirstSecond Quarter 2011 Compared with FirstSecond Quarter 2010
Net income increased by $1$20 million in the firstsecond quarter of 2011 compared to the firstsecond quarter of 2010 due to earnings associated with TrAIL and PATH ($522 million), partially offset by reduceddecreased earnings for ATSI ($41 million).
Revenues —
Revenues by transmission asset owner are shown in the following table:
                        
 Three Months    Three Months   
Revenues by Ended March 31 Increase  Ended June 30 Increase 
Transmission Asset Owner 2011 2010 (Decrease)  2011 2010 (Decrease) 
 (In millions)  (In millions) 
ATSI $52 $57 $(5) $54 $59 $(5)
TrAIL 14 — 14  46 — 46 
PATH 1 — 1  5 — 5 
              
Total Revenues $67 $57 $10  $105 $59 $46 
              
Expenses —
Total expenses increased by $5$9 million principally due primarily to operating expenses associated with TrAIL and PATH which were $3 million in the first quarter of 2011.operating expenses.
Other Expense —
Other expense increased $4$6 million in the firstsecond quarter of 2011 due to additional interest expense associated with TrAIL.
Competitive Energy Services — FirstSecond Quarter 2011 Compared with FirstSecond Quarter 2010
Net income decreased by $64$109 million in the firstsecond quarter of 2011, compared to the firstsecond quarter of 2010, primarily due to increased transmission expense, an inventory reserve adjustment,reduced sales margins, non-core asset impairments and the effect of mark-to-market adjustments.
Revenues —
Total revenues increased $204by $479 million in the firstsecond quarter of 2011 primarily due to growth in direct and governmentgovernmental aggregation sales and the inclusion of the Allegheny companies, partially offset by a decline in POLR sales.

 

8793

The increase in total revenues resulted from the following sources:
                        
 Three Months    Three Months   
 Ended March 31 Increase  Ended June 30 Increase 
Revenues by Type of Service 2011 2010 (Decrease)  2011 2010 (Decrease) 
 (In millions)  (In millions) 
 
Direct and Government Aggregation $840 $512 $328 
POLR 369 673  (304)
Direct and Governmental Aggregation $925 $586 $339 
POLR and Structured Sales 231 615  (384)
Wholesale 96 91 5  66 77  (11)
Transmission 26 17 9  30 19 11 
REC’s 32 67  (35)
RECs 12 — 12 
Other 41 33 8  38 37 1 
Allegheny Companies 193 — 193  511 — 511 
              
Total Revenues $1,597 $1,393 $204  $1,813 $1,334 $479 
              
  
Allegheny Companies
  
Direct and Government Aggregation $9 
POLR 68 
Direct and Governmental Aggregation $26 
POLR and Structured Sales 185 
Wholesale 91  267 
Transmission 12  32 
Other 13  1 
      
Total Revenues $193  $511 
      
 
 Three Months   
 Ended March 31 Increase 
MWH Sales by Type of Service 2011 2010 (Decrease) 
 (In thousands) 
Direct 9,671 5,854  65.2%
Government Aggregation 4,310 2,732  57.8%
POLR 5,714 13,276  (57.0)%
Wholesale 1,113 898  23.9%
Allegheny Companies 2,636 — — 
       
Total Sales 23,444 22,760  3.0%
       
 
Allegheny Companies
 
Direct 145 
POLR 812 
Structured Sales 284 
Wholesale 1,395 
   
Total Sales 2,636 
   
             
  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 $328$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 approximately 1.5 million residential and small commercial customers at the end of MarchJune 2011 compared to approximately 1.1 million such customers at the end of MarchJune 2010. In addition,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 5.2% colder17% cooler than in 2010.

88

The decrease in POLR revenues of $304$384 million was due to lower sales volumes to Met-Ed, Penelec and the Pennsylvania and Ohio Companies, partially offset by increased sales to non-associated companies and higher unit prices to the Pennsylvania Companies.Companies consistent with our business strategy. Participation in POLR auctions and RFPs are expected to continue but the concentrationproportion of these sales will primarily be dependentdepend on our success in ourhedge positions for direct retail and aggregation sales channels.sales.
Wholesale revenues increased $5decreased $11 million due to increased volumes partially offset by lowerreduced generation available for sale in the wholesale prices. The higher sales volumes were the result of increased short term (net hourly positions) transactions in MISO. $22 million of wholesale revenue resulted from long positions in MISO that were unable to be netted with short positions in PJM, due to separate settlement requirements with each RTO.market.

94

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 Government Aggregation (Decrease) 
  (In millions) 
Direct Sales:    
Effect of 65.2% increase in sales volumes $223 
Change in prices  (4)
    
   219 
    
Government Aggregation:    
Effect of 57.8% increase in sales volumes  100 
Change in prices  9 
    
   109 
    
Net Increase in Direct and Government Aggregation Revenues $328 
    
    
  Increase 
Source of Change in POLR Revenues (Decrease) 
  (In millions) 
POLR:    
Effect of 57.0% decrease in sales volumes $(384)
Change in prices  80 
    
   (304)
    
    
  Increase 
Source of Change in Wholesale Revenues (Decrease) 
  (In millions) 
Other Wholesale:    
Effect of 23.9% increase in sales volumes  12 
Change in prices  (7)
    
   5 
    
     
  Increase 
Source of Change in Direct and Governmental Aggregation (Decrease) 
  (In millions) 
Direct Sales:    
Effect of increase in sales volumes $267 
Change in prices  (13)
    
   254 
    
Governmental Aggregation:    
Effect of increase in sales volumes  80 
Change in prices  5 
    
   85 
    
Net Increase in Direct and Governmental Aggregation Revenues $339 
    
     
  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 $9by $11 million due primarily to higher MISOPJM congestion revenue. The revenues derived from the sale of RECs declined $35increased $12 million in the firstsecond quarter of 2011.
Expenses —
Total expenses increased $277by $624 million in the firstsecond quarter of 2011 due to the following:
Fuel costs increased $13decreased by $27 million primarily due to increaseddecreased volumes ($3156 million), partially offset by lowerhigher unit prices ($1829 million). Volumes increaseddecreased due to higherlower generation at the fossil units. UnitHigher unit prices declined primarily due to improved generating unit availability at more efficient units, partially offset byreflect increased coal transportation costs and higher nuclear fuel unit prices following the refueling outages that occurred in 2010.
Purchased power costs decreased $153 million due primarily towere unchanged as higher unit costs ($70 million) were offset by lower volumes purchased ($185 million) partially offset by higher unit costs ($3270 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. $35 million of purchased power expense resulted from long positions in MISO that were unable to be netted with short positions in PJM, due to separate settlement requirements with each RTO.
Fossil operating costs increased $1by $18 million due primarily to higher labor, contractor and materials and equipment costs partially offset by lower professionaldue to in increase in outages, both planned and contractor costs and reduced coal sale losses.unplanned, from the previous year.
Nuclear operating costs increased $15by $33 million due primarily to higher laborhaving two refueling outages, Perry and related benefits, partially offset by lower professional and contractor costs.Beaver Valley 2, occurring this year. While Davis-Besse had a refueling outage last year, the work performed during the second quarter of 2010 was largely capital-related.

89

Transmission expenses increased $111by $66 million due primarily to increases in PJM of $108$91 million from higher congestion, network, and line loss expense, andpartially offset by lower MISO transmission expenses of $3$25 million due to higher congestionlower network and line loss costs.
General taxes increased $3by $10 million due to an increase in revenue-related taxes.

95

Other expenses increased $65by $36 million primarily due to: a $54$14 million provision for excess and obsolete material relating to revised inventory practices adopted in connection with the Allegheny merger;mark-to-market adjustment; a $13$7 million impairment charge related to non-core assets; and an $11$8 million increase in intercompany billings;billings. The intercompany billings increased due to merger related costs and reduced mark-to-market adjustments of $15 million.increased intersegment billings for leasehold costs from the Ohio Companies.
The inclusion of approximately one month of the Allegheny companies’ operations contributed $222$488 million to expenses, including a $29$9 million mark-to-market adjustment relating primarily to power contracts.
Other Expense —
Total other expense in the firstsecond quarter of 2011 was $30$32 million higher than the firstsecond quarter of 2010, primarily due to a $35$34 million increase in net interest expense partially offset by an increase in nuclear decommissioning trust investment income ($52 million). The increase in interest expense was primarily due to the inclusion of the Allegheny companies ($2022 million) and lower capitalized interest ($1312 million) associated with the completion of the Sammis AQC project in 2010.
     
  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 — FirstSecond Quarter of 2011 Compared with FirstSecond Quarter of 2010
Financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a $35$47 million decrease in earnings available to FirstEnergy in the firstsecond quarter of 2011 compared to the same period in 2010. The decrease resulted primarily from increased operating expenses resulting from adverse litigation resolution ($29 million), decreased capitalized interest ($10 million) resulting from completed construction projects and increased interest expense due to the 2010 termination of interest rate swap agreements ($7 million).

96

Summary of Results of Operations — First Six Months of 2011 Compared with the First Six Months of 2010
Financial results for FirstEnergy’s business segments in the first six months of 2011 and 2010 were as follows:
                     
      Competitive  Regulated  Other and    
  Regulated  Energy  Independent  Reconciling  FirstEnergy 
First Six Months 2011 Financial Results Distribution  Services  Transmission  Adjustments  Consolidated 
  (In millions) 
Revenues:                    
External                    
Electric $4,527  $2,556  $—  $—  $7,083 
Other  226   180   172   (69)  509 
Internal  —   661   —   (617)  44 
                
Total Revenues  4,753   3,397   172   (686)  7,636 
                
                     
Expenses:                    
Fuel  97   991   —   —   1,088 
Purchased power  2,323   700   —   (617)  2,406 
Other operating expenses  824   1,288   36   (10)  2,138 
Provision for depreciation  269   195   25   13   502 
Amortization of regulatory assets  216   —   6   —   222 
General taxes  356   95   16   12   479 
                
Total Expenses  4,085   3,269   83   (602)  6,835 
                
                     
Operating Income  668   128   89   (84)  801 
                
Other Income (Expense):                    
Investment income  52   21   —   (21)  52 
Interest expense  (280)  (144)  (21)  (51)  (496)
Capitalized interest  4   22   1   11   38 
                
Total Other Expense  (224)  (101)  (20)  (61)  (406)
                
                     
Income Before Income Taxes  444   27   69   (145)  395 
Income taxes  164   10   25   (20)  179 
                
Net Income (Loss)  280   17   44   (125)  216 
Loss attributable to noncontrolling interest  —   —   —   (15)  (15)
                
Earnings available to FirstEnergy Corp. $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 
                

97

                     
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) 
Revenues:                    
External                    
Electric $(114) $1,148  $—  $—  $1,034 
Other  69   74   56   (12)  187 
Internal  (19)  (552)  —   548   (23)
                
Total Revenues  (64)  670   56   536   1,198 
                
                     
Expenses:                    
Fuel  97   307   —   —   404 
Purchased power  (363)  (80)  —   548   105 
Other operating expenses  134   596   6   28   764 
Provision for depreciation  59   47   6   7   119 
Amortization of regulatory assets  (151)  —   —   —   (151)
General taxes  64   31   2   1   98 
                
Total Expenses  (160)  901   14   584   1,339 
                
                     
Operating Income  96   (231)  42   (48)  (141)
                
Other Income (Expense):                    
Investment income  (2)  7   —   —   5 
Interest expense  (30)  (31)  (10)  (5)  (76)
Capitalized interest  2   (25)  —   (20)  (43)
                
Total Other Expense  (30)  (49)  (10)  (25)  (114)
                
                     
Income Before Income Taxes  66   (280)  32   (73)  (255)
Income taxes  21   (107)  11   9   (66)
                
Net Income  45   (173)  21   (82)  (189)
Loss attributable to noncontrolling interest  —   —   —   —   — 
                
Earnings available to FirstEnergy Corp. $45  $(173) $21  $(82) $(189)
                
Regulated Distribution — First Six Months of 2011 Compared to First Six Months of 2010
Net income increased by $45 million in the first six months of 2011, compared to the first six months of 2010, primarily due to the absence of a $35 million regulatory asset impairment recorded in 2010 and the earnings contribution of the Allegheny companies, partially offset by a favorable property tax settlement recognized in 2010.
Revenues —
The decrease in total revenues resulted from the following sources:
             
  Six Months    
  Ended June 30  Increase 
Revenues by Type of Service 2011  2010  (Decrease) 
  (In millions) 
Pre-merger companies:            
Distribution services $1,719  $1,733  $(14)
          
Generation sales:            
Retail  1,620   2,272   (652)
Wholesale  220   397   (177)
          
Total generation sales  1,840   2,669   (829)
          
Transmission  88   299   (211)
Other  123   116   7 
          
Total pre-merger companies  3,770   4,817   (1,047)
Allegheny companies  983   —   983 
          
Total Revenues $4,753  $4,817  $(64)
          

98

The decrease 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 are summarized in the following table:
             
          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%
          
Lower distribution deliveries to commercial customers reflected soft economic conditions in this sector and decreased weather-related usage in the first six months of 2011 as cooling degree days were 17% below the same period in 2010. The increase in distribution deliveries to industrial customers was primarily due to recovering economic conditions in the Utilities’ service territory compared to the first six months of 2010. Industrial deliveries increased by 12% to steel customers, 16% to electrical equipment and component manufacturing customers and 10% to non-metallic mineral customers, partially offset by 2% lower sales to automotive customers.
The following table summarizes the price and volume factors contributing to the $829 million decrease in generation revenues in the first six months of 2011 compared to the same period of 2010:
     
  Increase 
Source of Change in Generation Revenues (Decrease) 
  (In millions) 
Retail:    
Effect of decrease in sales volumes $(826)
Change in prices  174 
    
   (652)
    
Wholesale:    
Effect of decrease in sales volumes  (2)
Change in prices  (175)
    
   (177)
    
Net Decrease in Generation Revenues $(829)
    
The decrease in retail generation sales volume was due to increased customer shopping in the Ohio Companies’, Met-Ed’s and Penelec’s service territories in the first six months of 2011 compared to the same period in 2010. Total generation provided by alternative suppliers as a percentage of total KWH deliveries increased to 75% from 57% for the Ohio companies and to 48% from 9% for Met-Ed’s and Penelec’s service areas. The decrease in wholesale generation revenues reflected lower 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.

99

Expenses —
Total expenses decreased by $160 million due to the following:
Purchased power costs, excluding the Allegheny companies, were $843 million lower in the first six months of 2011 due to a decrease in volumes required. The decrease in power purchased from FES reflected the increase in customer shopping 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 costs in the first six months of 2011.
     
  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 decreased $124 million primarily due to lower PJM network transmission expenses and congestion costs of $177 million 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 ESP on March 23, 2010, partially offset by increased energy efficiency cost recovery.
Fuel expenses for MP were $97 million in the first six 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 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 
          
Expenses —
Total expenses increased by $14 million principally due to TrAIL and PATH operating expenses.
Other Expense —
Other expense increased $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 higher wholesale prices partially offset by decreased volumes. The lower sales volumes were the result of decreased short-term (net hourly positions) transactions in MISO. 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 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 increased 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 revised 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 Companies.

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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 —
Total other expense in the first six months of 2011 was $49 million higher than the first six months of 2010, primarily due to a $56 million increase in net interest expense, partially offset by an increase in nuclear decommissioning trust investment income ($7 million). The increase in interest expense was primarily due to the inclusion of the Allegheny companies ($30 million) and lower 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 on holding company debt and corporate support services revenues and expenses, resulted in an $82 million decrease in earnings available to FirstEnergy in the first six months of 2011 compared to the same period in 2010. The decrease resulted primarily from increased operating expenses resulting from adverse litigation resolution ($1729 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 2011 ($12 million) representing reconciling adjustments combined withand increased income taxes ($129 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 costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent amounts that are expected to be credited to customers through future regulated rates or amounts collected from customers for costs not yet incurred. FirstEnergy and the Utilities net their regulatory assets and liabilities based on federal and state jurisdictions. The following table provides the balance of net regulatory assets by company as of March 31,June 30, 2011 and December 31, 2010 and changes during the threesix months then ended:
                        
 March 31, December 31, Increase  June 30, December 31, Increase 
Regulatory Assets 2011 2010 (Decrease)  2011 2010 (Decrease) 
 (In millions)  (In millions) 
OE $385 $400 $(15) $393 $400 $(7)
CEI 337 370  (33) 320 370  (50)
TE 84 72 12  89 72 17 
JCP&L 460 513  (53) 469 513  (44)
Met-Ed 285 296  (11) 341 296 45 
Penelec 179 163 16  222 163 59 
Other* 354 12 342  348 12 336 
              
Total $2,084 $1,826 $258  $2,182 $1,826 $356 
              
   
* 2011 includes $343$337 million related to the Allegheny companies.

 

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The following tables provide information about the composition of net regulatory assets as of March 31,June 30, 2011 and December 31, 2010 and the changes during the threesix months then ended:
                
 Amount of 
 Increase 
             (Decrease) 
 March 31, December 31, Increase  June 30, December 31, Increase Attributable 
Regulatory Assets by Source 2011 2010 (Decrease)  2011 2010 (Decrease) to AE 
 (In millions)  (In millions) 
Regulatory transition costs $592 $770 $(178) $899 $770 $129 $— 
Customer receivables for future income taxes 488 326 162  502 326 176 160 
Loss on reacquired debt 56 48 8  53 48 5 8 
Employee postretirement benefits 14 16  (2) 11 16  (5) — 
Nuclear decommissioning, decontamination and spent fuel disposal costs  (200)  (184)  (16)
Nuclear decommissioning and spent fuel disposal costs  (201)  (184)  (17) — 
Asset removal costs  (220)  (237) 17   (228)  (237) 9 22 
MISO/PJM transmission costs 280 184 96  292 184 108 76 
Deferred generation costs 574 386 188  454 386 68 15 
Distribution costs 333 426  (93) 284 426  (142) — 
Other 167 91 76  116 91 25 56 
                
Total $2,084 $1,826 $258  $2,182 $1,826 $356 $337 
                
FirstEnergy had $390$385 million of net regulatory liabilities as of March 31,June 30, 2011, which includes $378including $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 $297$345 million as of March 31, 2011.June 30, 2011, of which $138 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 all-electric residential discountsregulatory transition costs and municipal taxes by OE, CEI and TE arePJM transmission costs of approximately $53 million, $32$144 million and $4$34 million, respectively. The timing of expected recovery of these assets cannot be determined at this time.
Regulatory assets not earning a current return primarily for regulatory transition costs by Met-Ed and Penelec are approximately $114 million and $5 million, respectively, and are expected to be recovered by 2020.
Regulatory assets not earning a current return primarily for JCP&L include certain storm damage costs and pension and postretirement benefits of approximately $34 million that are expected to be recovered by JCP&L are approximately $37 million. The timing of expected recovery of these assets cannot be determined at this time.2014.
Regulatory assets not earning a current return primarily for FirstEnergy’s other utility subsidiaries include certain deferred generation and other costs areof approximately $52$133 million by FirstEnergy’s other utility subsidiariesthat are expected to be recovered over various periods though 2012.2026.
CAPITAL RESOURCES AND LIQUIDITY
As of March 31,June 30, 2011, FirstEnergy had $476 million of cash and cash equivalents of approximately $1.1 billion available to fund investments, operations and capital expenditures. ToIn addition to internal sources to fund liquidity and capital requirements for 2011 and beyond, FirstEnergy may 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.
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 2011, FirstEnergy expects to satisfy these requirements with a combination of internal cash from operations and external funds from the capital markets as market conditions warrant. FirstEnergy also expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements along with continued access to long-term capital markets.
A material adverse change in operations, or in the availability of external financing sources, could impact FirstEnergy’s liquidity position and ability to fund its 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 in the competitive generation markets, operational excellence, business plan execution, well-positioned generation fleet, no speculative trading operations, appropriate long-term commodity hedging positions, manageable capital expenditure program, adequately funded pension plan, minimal near-term maturities of existing long-term debt, commitment to a secure dividend and a successful merger integration.

 

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As of March 31,June 30, 2011, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was principally due to the classification of certain variable interest rate PCRBs as currently payable long-term debt and short-term borrowings. Currently payable long-term debt as of March 31,June 30, 2011, included the following (in millions):
        
Currently Payable Long-term Debt  
PCRBs supported by bank LOCs(1)
 $827  $949 
AE Supply unsecured note 503 
FirstEnergy Corp. unsecured note 250 
FGCO and NGC unsecured PCRBs(1)
 141  136 
Penelec unsecured PCRBs 25 
FirstEnergy Corp. unsecured note 250 
WP unsecured note 80 
NGC collateralized lease obligation bonds 50  59 
Sinking fund requirements 49  50 
Other notes 43  31 
      
 $1,385  $2,058 
      
(1) Interest rate mode permits individual debt holders to put the respective debt back to the issuer prior to maturity.
Short-TermCredit Facility Borrowings and Liquidity
FirstEnergy had approximately $486$656 million and $700 million of short-term borrowings as of March 31,June 30, 2011 and $700 million as of December 31, 2010.2010, respectively. FirstEnergy’s available liquidity as of April 25,July 29, 2011, is summarized in the following table:
               
            Available 
Company Type Maturity Commitment  Liquidity 
        (In millions) 
FirstEnergy(1)
 Revolving Aug. 2012 $2,750  $1,983 
AE Revolving Apr. 2013  250   247 
AE Supply(2)
 Revolving Various  1,050   1,000 
FE Utilities & TrAIL Revolving 2013  910   475 
             
    Subtotal $4,960  $3,705 
    Cash  —   1,134 
             
    Total $4,960  $4,839 
             
               
            Available 
Company Type Maturity Commitment  Liquidity 
       (In millions) 
FirstEnergy(1)
 Revolving June 2016 $2,000  $1,751 
FES / AE Supply Revolving June 2016  2,500   2,449 
TrAIL Revolving Jan. 2013  450   450 
AGC Revolving Dec. 2013  50   — 
             
    Subtotal $5,000  $4,650 
    Cash  —   586 
             
    Total $5,000  $5,236 
             
(1) FirstEnergy Corp. and regulated subsidiary borrowers.
(2)Includes $50 million for AGC.
During March 2011, the accounts receivable financing arrangements for OE, TE, Penelec and Met-Ed were terminated in favor of other sources of liquidity that were deemed more economical. In May 2011, AE terminated its $250 million credit facility. AE now participates in the unregulated money pool (see FirstEnergy Money Pools below).
Revolving Credit Facilities
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 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 March 31,June 30, 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  33(2)
CEI  250(3) 500  $500 $500 
TE  250(3) 500  $500 $500 
JCP&L 425  411(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 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 $2.75 billion revolving credit facility, borrowers may request the issuance of LOCs expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under each of the facilityNew Facilities and against the applicable borrower’s borrowing sub-limit.
The $2.75 billion 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 March 31,June 30, 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
  57.656.9%
FES
  53.354.1%
OE
  55.056.2%
Penn
  35.034.4%
CEI
  56.456.3%
TE
  58.158.4%
JCP&L
  34.543.9%
Met-Ed
  44.353.5%
Penelec
  54.555.5%
ATSI
  49.654.9%
MP
59.3%
PE
60.1%
WP
53.9%
AE Supply
39.4%
As of March 31,June 30, 2011, FirstEnergy could issue additional debt of approximately $7.1$7.8 billion, or recognize a reduction in equity of approximately $3.8$4.2 billion, and remain within the limitations of the financial covenants required by its $2.75 billion revolving credit facility.

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The $2.75 billion revolving credit facility, doesNew Facilities do not contain provisions that restrict the ability to borrow or accelerate payment of outstanding advances as a result of any change in credit ratings. Pricing is 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.

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In addition to the $2.75 billion revolving credit facility,New Facilities, FirstEnergy also has access to an additional $2.2 billion$500 million of revolving credit facilities relating to the Allegheny companies. The following table summarizes the borrowing sub-limits for each borrower under the facilities as of March 31, 2011:
     
  Revolving 
  Credit Facility 
Borrower Sub-Limit 
  (In millions) 
AE $250 
AE Supply  1,000 
MP  110 
PE  150 
WP  200 
AGC  50 
TrAIL  450 
companies (TrAIL — $450 million and AGC $50 million).
Under the terms of their individualits credit facilities,facility, outstanding debt of AE Supply, MP, PE, WP and AGC may not exceed 65% of the sum of theirits debt and equity as of the last day of each calendar quarter. Outstanding debt for TrAIL may not exceed 70% and 65% of the sum of its debt and equity as of the last day of each calendar quarter through June 30, 2011 and December 31, 2012, respectively. These provisions limit debt levels of these subsidiaries and also limit the net assets of each subsidiary that may be transferred to AE.
FirstEnergy, the Utilities, FES and AESC are currently pursuing an aggregate of up to $4.0 billion in new multi-year revolving credit facilities to replace a portion of the existing facilities described above.
FirstEnergy Money Pools
FirstEnergy’s regulated companies, excluding regulated companies acquired in the Allegheny merger, also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy’s unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first quartersix months of 2011 was 0.38%0.43% per annum for the regulated companies’ money pool and 0.47%0.46% per annum for the unregulated companies’ money pool. In March 2011, AE Supply invested $200 million into the unregulated money pool. FirstEnergy and its regulated companies acquired in the Allegheny merger have filed with the appropriate regulatory commissions to receive approval to bebecome part of the FirstEnergy regulated money pool.
Pollution Control Revenue Bonds
As of March 31,June 30, 2011, FirstEnergy’s currently payable long-term debt included approximately $827$949 million (FES — $778$875 million, Met-Ed — $29 million and Penelec — $20$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 March 31,June 30, 2011:
                
 Aggregate LOC Reimbursements of Aggregate LOC Reimbursements of
LOC Bank Amount(1) 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 178 Beginning June 2012 Multiple dates(2)
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
US Bank 60 April 2014 6 months 60 April 2014 6 months
UBS 272 April 2014 April 2014
            
Total $959     $959    
            
(1) Includes approximately $10 million of applicable interest coverage.
 
(2) Shorter of 6 months or LOC termination date ($49 million) and shorter of one year or LOC termination date ($129 million).

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On March 17, 2011, FES completed the remarketing of $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 non-LOC backed fixed rate PCRBs that were subject to purchase on demand by the owner on that date.
On April 1, 2011, FES completed the remarketing of an additional $97 million of 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 will bewere cancelled on May 31, 2011.
On April 29, Met-Ed redeemed $14 million of PCRBs at par value.
On June 1, 2011, FGCO repurchased $40 million of PCRBs and, subject to market conditions and other considerations, is holding those bonds for future remarketing or refinancing.
On July 29, 2011, FGCO and NGC provided notice to the trustee for $158.1 million and $158.9 million, respectively, of PCRBs of their election to terminate applicable supporting LOCs. As a result, these PCRBs are subject to mandatory purchase on September 1, 2011. Subject to market conditions and other 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 FMBs previously delivered to certain of the LOC providers by FGCO and NGC, respectively, will be cancelled in connection with the mandatory purchases.
Long-Term Debt Capacity
As of March 31,June 30, 2011, the Ohio Companies and Penn had the aggregate capability to issue approximately $2.4$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 $118$100 million and $17$19 million, respectively. As a result of its indenture provisions, TE cannot incur any additional secured debt. Met-Ed and Penelec had the capability to issue secured debt of approximately $365$363 million and $346$365 million, respectively, under provisions of their senior note indentures as of March 31,June 30, 2011. In addition, based upon their respective FMB indentures, net earnings and available bondable property additions as of March 31,June 30, 2011, MP, PE and WP had the capability to issue approximately $685 million$1.0 billion of additional FMBs in the aggregate.
Based upon FGCO’s FMB indenture, net earnings and available bondable property additions under its FMB indentures as of March 31,June 30, 2011, FGCO had the capability to issue $2.4$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 $1.2$1.7 billion of additional FMBs as of March 31, 2011.June 30, 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 March 1, 2011, Fitch affirmed the ratings and outlook of FirstEnergy and its subsidiaries. On February 25, 2011, Moody’s affirmed the ratings and stable outlook of FirstEnergy and its regulated 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 outlook of FirstEnergy and its subsidiaries. The following table displays FirstEnergy’s and its subsidiaries’ securities ratings as of March 31,July 29, 2011.
             
  Senior Secured Senior Unsecured
Issuer S&P Moody’s Fitch S&P Moody’s Fitch
FirstEnergy Corp. — — — BB+ Baa3 BBB
Allegheny — — — BB+ Baa3 BBB-—
FES — — — BBB- Baa2 BBB
AE Supply BBB Baa2 BBB BBB- Baa3 BBB-
AGC — — — BBB- Baa3 BBB-BBB+
ATSI — — — BBB- Baa1 —A-
CEI BBB Baa1 BBB BBB- Baa3 BBB-
JCP&L — — — BBB- Baa2 BBB+
Met-Ed BBB A3 BBB+A- BBB- Baa2 BBBBBB+
MP BBB+ Baa1 BBB+A- BBB- Baa3 BBB-BBB+
OE BBB A3 BBB+ BBB- Baa2 BBB
Penelec BBB A3 BBB+ BBB- Baa2 BBB
Penn BBB+ A3 BBB+ — — —
PE BBB+ Baa1 BBB+A- BBB- Baa3 BBB-BBB+
TE BBB Baa1 BBB — — —
TrAIL — — — BBB- Baa2 BBBA-
WP BBB+ A3 BBB+A- BBB- Baa2 BBB-BBB+

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Changes in Cash Position
As of March 31,June 30, 2011, FirstEnergy had $1.1 billion$476 million of cash and cash equivalents compared to approximately $1 billion as of December 31, 2010. As of March 31,June 30, 2011 and December 31, 2010, FirstEnergy had approximately $73$78 million and $13 million, respectively, of restricted cash included in other current assets on the Consolidated Balance Sheet.

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During the first threesix months of 2011, FirstEnergy received $240 million of$1.4 billion from cash dividends fromand equity repurchases by its subsidiaries and paid $190$420 million in cash dividends to common shareholders, including $20 million paid in March by AlleghenyAE 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 decreasedincreased by $15$173 million during the first threesix months of 2011 compared to the comparablesame period in 2010, as summarized in the following table:
                        
 Three Months    Six Months   
 Ended March 31 Increase  Ended June 30 Increase 
Operating Cash Flows 2011 2010 (Decrease)  2011 2010 (Decrease) 
 (In millions)  (In millions) 
Net income $45 $149 $(104) $216 $405 $(189)
Non-cash charges and other adjustments 515 367 148 
Non-cash charges 1,229 789 440 
Pension trust contribution  (157) —  (157)  (262) —  (262)
Working capital and other 88  (10) 98   (152)  (336) 184 
              
 $491 $506 $(15) $1,031 $858 $173 
              
The increase in non-cash charges and other adjustments is primarily due to increased deferred taxes and investment tax credits ($112 million), increased asset impairments ($19 million), changes in accrued compensationdriven by bonus depreciation and retirement benefitsthe 2011 pension contribution ($68393 million) and increased depreciation from the acquired Allegheny Companies ($27119 million), partially offset by lower amortization of regulatory assets from reduced net PJM transmission cost and transition cost recovery ($80151 million).
The increase in cash flows from working capital and other is primarily due to decreased receivables from higher customer collections ($162 million), decreased prepayments and other current assets ($85355 million) and decreased materials and supplies from the inventory valuation adjustment in the first quarter of 2011 ($8241 million), partially offset by decreased accruedincreased prepayments and other current assets driven by higher prepaid taxes ($189 million) and decreased accounts payable ($33187 million).
Cash Flows From Financing Activities
In the first threesix months of 2011, cash used for financing activities was $550$1,039 million compared to $594$484 million in the first three monthscomparable period of 2010. The following table summarizes security issuancesnew debt financing (net of any discounts) and redemptions:
                
 Three Months  Six Months 
 Ended March 31  Ended June 30 
Securities Issued or Redeemed 2011 2010 
Debt Issuances and Redemptions 2011 2010 
 (In millions)  (In millions) 
New Issues
  
Pollution control notes 150 —  $272 $— 
Long-term revolvers 60 — 
Long-term revolving credit 70 — 
Unsecured Notes 7 —  161 — 
          
 $217 $—  $503 $— 
          
  
Redemptions
  
Pollution control notes  (200) —  $312 $251 
Long-term revolvers  (20) — 
Long-term revolving credit 475 — 
Senior secured notes  (109) 9  166 55 
First mortgage bonds 14 — 
Unsecured notes  (30) 100  35 100 
          
 $(359) $109  $1,002 $406 
          
  
Short-term borrowings, net $(214) $(295) $(44) $281 
          
On March 29,In 2011, FES paid off at maturity a $100 million term loan that was secured by FMBs that was scheduled to mature on March 31, 2011. OnFMBs. In April 8, 2011, FirstEnergy entered into a $150 million unsecured term loan with an April 2013 maturity.

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In March 2011 FES repurchased and retired $20 million of its 6.80% unsecured senior notes and $10$15 million of its 6.05% unsecured senior notes originally outstanding in the principal amounts of $500 million and $600 million, respectively. Additionally, onnotes. In April 29, 2011, Met-Ed redeemed approximately $14 million of FMBs securing PCRBs.
During the remainder of 2011 FirstEnergy and its subsidiaries expect to pursue, from time to time, continued reductions in outstanding long-term debt of up to approximately $1.0 to $1.5 billion including through redemptions, open market or privately negotiated purchases. Any such transactions will be subject to prevailing market conditions, liquidity requirements, timing of asset sales and other factors.

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Cash Flows From Investing Activities
Cash flows received fromused for investing activities in the first threesix months of 2011 resulted primarily from cash used for property additions, partially offset by the cash acquired in the Allegheny merger, partially offset by cash used for property additions.merger. The following table summarizes investing activities for the first threesix months of 2011 and the comparable period of 2010 by business segment:
                                
Summary of Cash Flows Property        Property       
Provided from (Used for) Investing Activities Additions Investments Other Total  Additions Investments Other Total 
 (In millions)  (In millions) 
Sources (Uses)
  
Three Months Ended March 31, 2011
 
Six Months Ended June 30, 2011
 
Regulated distribution $(177) $60 $(9) $(126) $(479) $(2) $(25) $(506)
Competitive energy services  (214)  (15)  (8)  (237)  (411)  (32)  (335)  (778)
Regulated independent transmission  (27)  (1) —  (28)  (72)  (1)  (1)  (74)
Other  (31) 590 145 704 
Inter-Segment reconciling items —  (22)  (150)  (172)
Cash received in Allegheny merger — 590 — 590 
Other and reconciling items  (56)  (21) 310 233 
                  
Total $(449) $612 $(22) $141  $(1,018) $534 $(51) $(535)
                  
  
Three Months Ended March 31, 2010
 
Six Months Ended June 30, 2010
 
Regulated distribution $(152) $62 $(6) $(96) $(309) $87 $(18) $(240)
Competitive energy services  (329) —  (1)  (330)  (619)  (11)  (1)  (631)
Regulated independent transmission  (14) —  (1)  (15)  (29) —  (2)  (31)
Other  (13) — —  (13)
Inter-Segment reconciling items —  (22) —  (22)
Other and reconciling items  (40)  (25) —  (65)
                  
Total $(508) $40 $(8) $(476) $(997) $51 $(21) $(967)
                  
Net cash provided fromused in investing activities induring the first threesix months of 2011 increaseddecreased by $617$432 million compared to the first three monthssame period of 2010. The increasedecrease was principally due to cash acquired in the Allegheny merger ($590 million), partially offset by a decrease in purchases of customer intangibles by FES in the customer acquisition process ($100 million) and a decrease in property additions ($59 million), principally due to lower AQC system expenditures, partially offset by decreasednet proceeds from asset sales and higher property additions ($114137 million).
During the remaining nine monthssecond half of 2011, capital requirements for property additions and capital leases are expected to be approximately $1.8 billion. This includes$1.2 billion, including approximately $90$122 million offor nuclear fuel expenditures.
CONTRACTUAL OBLIGATIONS
Estimated cash payments for contractual obligations that are considered firm obligations acquired by FirstEnergy in the AE merger are summarized as follows:
                     
          2012-  2014-    
Contractual Obligations Total  2011  2013  2015  Thereafter 
  (In millions) 
Long-term debt(1)
 $4,776  $8  $1,445  $1,037  $2,286 
Interest on long-term debt(2)
  2,516   240   470   341   1,465 
Fuel and purchased power(3)
  9,781   956   2,160   1,650   5,015 
Capital expenditures  141   117   24   —   — 
Pension funding (4)
  695   124   175   186   210 
                
                     
Total $17,909  $1,445  $4,274  $3,214  $8,976 
                
(1)Does not include payments made and debt issued subsequent to March 31, 2011.
(2)Interest on variable-rate debt is based on interest rates as of March 31, 2011.
(3)Amounts under contract with fixed or minimum quantities are based on estimated annual requirements.
(4)Estimated contributions through 2021 based on current actuarial assumptions.
fuel.
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 March 31,June 30, 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)
 $231  $223 
FirstEnergy guarantee of OVEC obligations 300 
OVEC obligations 300 
Other(2)
 228  301 
      
 759  824 
      
  
Subsidiaries’ Guarantees  
Energy and Energy-Related Contracts 158  155 
FES’ guarantee of NGC’s nuclear property insurance 70  70 
FES’ guarantee of FGCO’s sale and leaseback obligations 2,375  2,324 
Other 18  19 
      
 2,621  2,568 
      
  
Surety Bonds 138  136 
LOC (non-debt)(3)
 318 
LOC(3)
 269 
      
 456  405 
      
Total Guarantees and Other Assurances $3,836  $3,797 
      
(1) Issued for open-ended terms, with a 10-day termination right by FirstEnergy.
 
(2) Includes guarantees of $15$95 million for nuclear decommissioning funding assurances, $161 million supporting OE’s sale and leaseback arrangement, and $37$35 million for railcar leases.
 
(3) Includes $146$105 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facilities, $130$122 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $42$39 million pledged in connection with the sale and leaseback of Perry by OE.
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 March 31,June 30, 2011, FirstEnergy’s maximum exposure under these collateral provisions was $557$625 million, as shown below:
                         
Collateral Provisions FES AE Supply Utilities Total  FES AE Supply Utilities Total 
 (In millions)  (In millions) 
Credit rating downgrade to below investment grade(1)
 $357 $10 $66 $433  $440 $4 $78 $522 
Material adverse event(2)
 54 57 13 124  33 57 13 103 
                  
Total $411 $67 $79 $557  $473 $61 $91 $625 
                  
(1) Includes $138$206 million and $46$59 million that is also considered an acceleration of payment or funding obligation atfor FES and the Utilities, respectively.
 
(2) Includes $53$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 $623$666 million, as shown below:
                         
Collateral Provisions FES AE Supply Utilities Total  FES AE Supply Utilities Total 
 (In millions)  (In millions) 
Credit rating downgrade to below investment grade(1)
 $420 $8 $66 $494  $477 $5 $78 $560 
Material adverse event(2)
 60 56 13 129  36 57 13 106 
                  
Total $480 $64 $79 $623  $513 $62 $91 $666 
                  
(1) Includes $138$206 million and $46$59 million that is also considered an acceleration of payment or funding obligation atfor FES and the Utilities, respectively.
 
(2) Includes $53$32 million that is also considered an acceleration of payment or funding obligation atfor FES.
Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $138$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, contracts entered into by the Competitive Energy Services segment, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions that 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 March 31,June 30, 2011 and forward prices as of that date, FES and AE Supply have posted collateral of $158$138 million and $5$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 $52$17 million of collateral. Depending on the volume of forward contracts and future price movements, higher amounts for margining could be required to be posted.
In connection with FES’ obligations to post and maintain collateral under the two-year PSA entered into by FES and the Ohio Companies following the CBP auction on May 13-14, 2009, NGC entered into a Surplus Margin Guaranty in an amount up to $500 million. The Surplus Margin Guaranty is secured by an NGC FMB issued in favor of the Ohio Companies.
FES’ debt obligations are generally guaranteed by its subsidiaries, FGCO and NGC, and FES guarantees the debt obligations of each of FGCO and NGC. Accordingly, present and future holders of indebtedness of FES, FGCO and NGC maywould 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.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.
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 March 31,June 30, 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 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 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 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.

 

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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 65 to the consolidated financial statements). Sources of information for the valuation of commodity derivative contracts as of March 31,June 30, 2011 are summarized by year in the following table:
                                                        
Source of Information-                              
Fair Value by Contract Year 2011 2012 2013 2014 2015 Thereafter Total  2011 2012 2013 2014 2015 Thereafter Total 
 (In millions)  (In millions) 
Prices actively quoted(1)
 $— $— $— $— $— $— $—  $— $— $— $— $— $— $— 
Other external sources(2)
  (315)  (152)  (44)  (36) — —  (547)  (287)  (169)  (48)  (38) — —  (542)
Prices based on models  (11) — — — 19 106 114  9  (3) — — — 44 50 
                              
Total(3)
 $(326) $(152) $(44) $(36) $19 $106 $(433) $(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 $366$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 March 31,June 30, 2011, an adverse 10% change in commodity prices would decrease net income by approximately $12$31 million ($720 million net of tax) during the next 12 months.
Equity Price Risk
FirstEnergy provides a noncontributory qualified defined benefit pension planplans that coverscover substantially all of its employees other than Allegheny employees employed by FirstEnergy and non-qualified pension plans that cover certain employees (the FirstEnergy Pension Plan). In addition, effective on the date of the merger, FirstEnergy provides noncontributory qualified defined pension plan benefits that cover substantially all of Allegheny employees employed by FirstEnergy and a supplemental executive retirement plan that covers certain Allegheny executives employed by FirstEnergy (the Allegheny Pension Plan).employees. The FirstEnergy Pension Plan and the Allegheny Pension Planplans provide defined benefits based on years of service and compensation levels.
Eligible FirstEnergy retirees,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 are provided other postretirement benefits such as a minimum amount of noncontributory life insurance, optional contributory insurance and certain health care benefits. These other postretirement benefits are not provided insurvivors. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for employees hired on or after January 1, 2005.
Eligible Allegheny retirees and dependents are provided other postretirement benefits such as subsidies for medical and life insurance plans. Subsidized medical coverage is not provided in retirement to Allegheny employees employed by FirstEnergy that were hired on or after January 1, 1993, with the exception of certain union employees who were hired or became members before May 1, 2006.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 March 31,June 30, 2011, the FirstEnergy pension plan was invested in approximately 32%31% of equity securities, 47%46% of fixed income securities, 10%9% of absolute return strategies, 5%6% of real estate, 2%4% of private equity and 4% of cash. The FirstEnergy Pension Plan and the Allegheny Pension Plan were 86% and 78%, respectively, funded on an accumulated benefit obligation basis as of March 31, 2011. A decline in the value of pension plan assets could result in additional funding requirements. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. During the first quarter ofthree months and six months ended June 30, 2011, FirstEnergy made a $157 million contributioncontributions to its qualified pension plans.plans of $105 million and $262 million, respectively. FirstEnergy intends to make additional contributions of $220$116 million and $6$2 million to its qualified pension plans and postretirement benefit plans, respectively, in the last threetwo 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 March 31,June 30, 2011, approximately 85%87% of the funds were invested in fixed income securities, 9%10% of the funds were invested in equity securities and 6%3% were invested in short-term investments, with limitations related to concentration and investment grade ratings. The investments are carried at their market values of approximately $1,741$1,779 million, $194$197 million and $115$69 million for fixed income securities, equity securities and short-term investments, respectively, as of Mach 31,June 30, 2011, excluding $(31)$6 million of receivables, payables, deferred taxes and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $19$20 million reduction in fair value as of March 31,June 30, 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 nuclear decommissioning trustsNDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements. InDuring the first threesix months of 2011, approximately $1 million, was contributed to JCP&L’s nuclear decommissioning trusts. During the second quarter of 2011, FirstEnergy intends to contribute approximately $4 million and $1 million was contributed to theNDT of JCP&L, OE and TE, nuclear decommissioning trusts, respectively, to comply with requirements under certain sale-leaseback transactions in which OE and TE continue as lessees.respectively. 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 $93$92 million. This estimate encompasses the shortfall covered by the existing $15On June 24, 2011, FENOC submitted a $95 million parental guarantee. FENOC agreed to increase the parental guarantee to $95 million within 90 days of the submittal.NRC for 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 March 31,June 30, 2011, the largest credit concentration was with J.P. Morgan Chase & Co., which is currently rated investment grade, representing 13.4%11% of FirstEnergy’s total approved credit risk comprised of 5.9%2.4% for FES, 2.1%1.6% for JCP&L, 2.7%2.0% for Met-Ed, 3.4% for WP and a combined 2.7%2.0% for OE, TE and CEI.the Ohio Companies.
OUTLOOK
Reliability Initiatives
Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES, FGCO, FENOC, and ATSI and TrAIL Company.TrAIL. The NERC asis the ERO is charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including ReliabilityFirstCorporation. All of FirstEnergy’s facilities are located within the ReliabilityFirstregion. FirstEnergy actively participates in the NERC and ReliabilityFirststakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by the ReliabilityFirstCorporation.
FirstEnergy believes that it generally is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such items are found, FirstEnergy develops information about the item and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an item to 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. This event did not result in a fault, outage, operation of protective equipment, or any other meaningful electric effect on any FirstEnergy transmission facilities or systems. On August 25, 2010, ReliabilityFirstissued a Notice of Enforcement to investigate the incident. FirstEnergy submitted a data response to ReliabilityFirston September 27, 2010. In March 2011, ReliabilityFirstsubmitted its proposed findings and settlement. At this time, FirstEnergy is evaluating ReliabilityFirst’s proposal and is unable to predict thesettlement, although a final outcome of this investigation.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 violation investigations with regard to certain matters of compliance by Allegheny.
Maryland
In 1999, Maryland adopted electric industry restructuring legislation, which gave PE’s Maryland retail electric customers the right to choose their electricity generation suppliers. PE remained obligated to provide standard offer generation service (SOS) at capped rates to residential and non-residential customers for various periods. The longest such period, for residential customers, expired on December 31, 2008. PE implemented a rate stabilization plan in 2007 that was designed to transition customers from capped generation rates to rates based on market prices and that concluded on December 31, 2010. PE’s transmission and distribution rates for all customers are subject to traditional regulated utility ratemaking (i.e., cost-based rates).
By statute enacted in 2007, the obligation of Maryland utilities to provide SOSstandard 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. In August 2007, PE filed a plan for seeking bids to serve its Maryland residential load for the period after the expiration of rate caps. The MDPSC approved the plan and PE now conducts rolling auctions to procure the power supply necessary to serve its customer load.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.

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In September 2009, the MDPSC opened a new proceeding to receive and consider proposals for construction of new generation resources in Maryland. In December 2009, Governor Martin O’Malley filed a letter in this proceeding in which he characterized the electricity market in Maryland as a “failure” and urged the MDPSC to use its existing authority to order the construction of new generation in Maryland, vary the means used by utilities to procure generation and include more renewables in the generation mix. In August 2010, the MDPSC opened another new proceeding to solicit comments on the PJM RPM process. Public hearings on the comments were held in October 2010. In December 2010, the MDPSC issued an order soliciting comments on a model request for proposal for solicitation of long-term energy commitments by Maryland electric utilities. PE and numerous other parties filed comments, and at this time no further proceedings have been set by the MDPSC in this matter.
In September 2007, the MDPSC issued an order that required the Maryland utilities to file detailed plans for how they will meet the “EmPOWER Maryland” proposal that in Maryland, electric consumption be reduced by 10% and electricity demand be reduced by 15%, in each case by 2015. In October 2007, PE filed its initial report on energy efficiency, conservation and demand reduction plans in connection with this order. The MDPSC conducted hearings on PE’s and other utilities’ plans in November 2007 and May 2008.
In a related development, theThe Maryland legislature in 2008 adopted a statute codifying the EmPOWER Maryland goals. In 2008, PE filed its comprehensive plans for attempting to achieve those goals, asking the MDPSC to approve programs for residential, commercial, industrial, and governmental customers, as well as a customer education program, and a pilot deployment of Advanced Utility Infrastructure (AUI) that Allegheny had previously tested in West Virginia.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. The AUI pilot was placed on a separate track to be re-examined after further discussion with the Staff of the MDPSC and other stakeholders. Meanwhile, extensive meetings with the MDPSC Staff and other stakeholders to discuss details of PE’s plans for additional and improved programs for the period 2012-2014 began in April 2011 and those programs are to be filed by September 1, 2011.

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In March 2009, the Maryland PSCMDPSC issued an order suspending until further notice the right of all electric and gas utilities in the state to terminate service to residential customers for non-payment of bills. The MDPSC subsequently issued an order making various rule changes relating to terminations, payment plans, and customer deposits that make it more difficult for Maryland utilities to collect deposits or to terminate service for non-payment. PE and several other utilities filed requests for reconsideration of various parts of the order, which were denied. The MDPSC is continuing to conduct hearings and collect data on payment plan and related issues and has adopted a set of proposed regulations that expand the summer and winter “severe weather” termination moratoria when temperatures are very high or very low, from one day, as provided by statute, to three days on each occurrence.
On March 24, 2011, the MDPSC held an initial hearing to discuss possible new regulations relating to service interruptions, storm response, call center metrics, and related reliability standards. The proposed rules included provisions for civil penalties for non-compliance. Numerous parties filed comments on the proposed rules and participated in the hearing, with many noting issues of cost and practicality relating to implementation. Concurrently, theThe Maryland legislature is consideringpassed a bill addressing the same topics. The final bill passed 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 is directed 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.
In December 2009, PErules, with proposed rules to be filed an application withby September 15, 2011. Separately, on April 7, 2011, the MDPSC for authorizationinitiated a rulemaking with respect to constructissues related to contact voltage. On June 3, 2011, the Maryland portions ofMDPSC’s Staff issued a report and draft regulations. Comments on the PATH Projectdraft regulations were submitted on June 17, 2011, and a hearing was held July 7, 2011. Final regulations related to be owned by PATH Allegheny Maryland Transmission Company, LLC, which is owned by Potomac Edison and PATH-Allegheny. On February 28, 2011, PE withdrew its application. See “Transmission Expansion” in the Federal Regulation and Rate Matters section for further discussion of this matter.contact voltage have not yet been adopted.
New Jersey
JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers, costs incurred under NUG agreements, and certain other stranded costs, exceed amounts collected through BGS and NUG rates and market sales of NUG energy and capacity. As of March 31, 2011, the accumulated deferred cost balance was a credit of approximately $102 million. To better align the recovery of expected costs, in July 2010, JCP&L filed a request to decrease the amount recovered for the costs incurred under the NUG agreements by $180 million annually, which the NJBPU approved, allowing the change in rates to become effective March 1, 2011.
In March 2009 and again in February 2010, JCP&L filed annual SBC Petitions with the NJBPU that included a requested zero level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009 estimated at $736 million (in 2003 dollars). Both matters are currently pending beforeIn its order of June 15, 2011, the NJBPU.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).
Ohio
The Ohio Companies operate under an ESP, which expires on May 31, 2011, that provides for generation supplied through a CBP. The ESP also allows the 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).
In March 2010, the Ohio Companies filed an application for a new ESP, which the PUCO approved in August 2010, with certain modifications. The new ESP will go into effect on June 1, 2011 and conclude on May 31, 2014. The material terms of the new ESP include: generation supplied through a CBP similar to the one used in May 2009 and the one proposed on the October 2009 MRO filingcommencing 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 tranches assigned post-auction; a 6% generation discount to certain low income customers provided by the Ohio Companies through a bilateral wholesale contract with FES;FES (FES is one of the wholesale suppliers to the Ohio Companies); no increase in base distribution rates through May 31, 2014; and a new distribution rider, Delivery Capital Recovery Rider (Rider DCR), to recover a return of, and on, capital investments in the delivery system. Rider DCR substitutes for Rider DSI which terminates under the current ESP. The Ohio Companies also agreed not to recover from retail customers 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-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 agreed to additional matters related to energy efficiency and alternative energy requirements. Many of the existing riders approved in the previous ESP remain in effect, with some modifications. The new ESP resolved proceedings pending at the PUCO regarding corporate separation, elements of the smart grid proceeding and expenses related to the ESP.

 

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Under the provisions 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 arewere 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. Because of the delay in issuing the Order, the launch of the programs included in the plan for 2010 was delayed and will launch during the second quarter of this year. As a result, OE fell short of its statutory 2010 energy efficiency and peak demand reduction benchmarks. Therefore,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 modify the Companies’ 2010 (and 2011 and 2012) energy efficiency benchmarks when addressing the portfolio plan, the Ohio Companies were not certain of their 2010 energy efficiency obligations. Therefore, CEI and TE (each of which achieved its 2010 energy efficiency and peak demand reduction statutory benchmarks) also requested an amendment if and only to the degree one was deemed necessary to bring these them into compliance with their yet-to-be-defined modified benchmarks. 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 Companiescompanies 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 2009.2009 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. In March 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 requirements be increased to include the shortfall for the 2009 solar REC benchmark. FES also applied for a force majeure determination from the PUCO regarding a portion of their compliance with the 2009 solar energy resource benchmark. On February 23, 2011, the PUCO granted FES’ force majeure request for 2009 and increased its 2010 benchmark by the amount of SRECs that FES was short of in its 2009 benchmark. In July 2010, the Ohio Companies initiated an additional RFP to secure RECs and solar RECs needed to meet the Ohio Companies’ alternative energy requirements as set forth in SB221 for 2010 and 2011 and executed related contracts in August 2010. On April 15, 2011, the Ohio Companies filed an application seeking an amendment to each of their 2010 alternative energy requirements for solar RECs generated in Ohio on the basis that an insufficient quantity of solar resources are available in the market but reflecting solar RECs that they have obtained and providing additional information regarding efforts to secure solar RECs. 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 rates and what they pay with the new credit in place. Tariffs implementing this new credit went into effect in March 2010. In April 2010, the PUCO issued a Second Entry on Rehearing that expanded the group of customers to which the new credit would apply and authorized deferral for the associated additional amounts. The PUCO also stated that it expected that the new credit would remain in place through at least the 2011 winter season and charged its staff to work with parties to seek a long term solution to the issue. Tariffs implementing this newly expanded credit went into effect in May 2010 and the proceeding remains open. The hearing on the matter was held in February 2011. The matter has now been briefedPUCO 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 awaitfiled their responses on July 5, 2011. The PUCO has not yet acted on the PUCO’s decision.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 and forcharges. Pursuant to the use of these funds to mitigate future generation rate increases whichplan approved by the PPUC, approved.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. The argument beforeOn June 14, 2011, the Commonwealth Court en banc, was heldissued 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 December 2010.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 inthrough the appealjudicial process and therefore expect to fully recover the approximately $252.7$254 million ($188.0189 million for Met-Ed and $64.7$65 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011.
In May 2008, May 2009 and May 2010, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider for the annual periods between June 1, 2008 to December 31, 2010, including marginal transmission losses as approved by the 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.
Met-Ed and Penelec filed with the PPUC a generation procurement plan covering the period January 1, 2011 through May 31, 2013. The plan is designed to provide adequate and reliable service through a prudent mix of long-term, short-term and spot market generation supply with a staggered procurement schedule that varies by customer class, using a descending clock auction. In August 2009, the parties to the proceeding filed a settlement agreement of all but two issues, and the PPUC entered an Order approving the settlement and the generation procurement plan in November 2009. Generation procurement began in January 2010.
In February 2010, Penn filed a Petition for Approval of its Default Service Plan for the period June 1, 2011 through May 31, 2013. In July 2010, the parties to the proceeding filed a Joint Petition for Settlement of all issues. Although the PPUC’s Order approving the Joint Petition held that the provisions relating to the recovery of MISO exit fees and one-time PJM integration costs (resulting from Penn’s June 1, 2011 exit from MISO and integration into PJM) were approved, it made such provisions subject to the approval of cost recovery by FERC. Therefore, Penn may not put these provisions into effect until FERC has approved the recovery and allocation of MISO exit fees and PJM integration costs.
Pennsylvania adopted Act 129 in 2008 to address issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters; and alternative energy. Among other things, Act 129 required utilities to file with the PPUC an energy efficiency and peak load reduction plan, or EE&C Plan, by July 1, 2009, setting forth the utilities’ plans to reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of 4.5% by May 31, 2013. Act 129 also required utilities to file with the PPUC a Smart Meter Implementation Plan (SMIP).
The PPUC entered an Order 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 held 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 Commonwealth Court pending possible settlement of WP’s SMIP. In September 2010, WP filed an amended EE&C Plan that is less reliant on smart meter deployment, which the PPUC approved in January 2011.

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Met-Ed, Penelec and Penn jointly filed a SMIP with the PPUC in August 2009. This plan proposed 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 of 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 SMIP as modified by the ALJ, including: ensuring that the smart meters to be deployed include the capabilities listed in the PPUC’s Implementation Order; denying the recovery of interest through the automatic adjustment clause; providing for the recovery of reasonable and prudent costs net of resulting savings from installation and use of smart meters; and requiring that administrative start-up costs be expensed and the costs incurred for research and development in the assessment period be capitalized. In April 2010, the PPUC adopted a Motion by Chairman Cawley that modified the ALJ’s initial decision, and decided various issues regarding the SMIP for Met-Ed, Penelec and Penn. The PPUC entered its Order in June 2010, consistent with the Chairman’s Motion. Met-Ed, Penelec and Penn filed a Petition for Reconsideration of a single portion of the 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, which contemplated deployment of 375,000 smart meters by May 2012, complied with the requirements of Act 129 and recommended approval of the alternative plan, including WP’s proposed cost recovery mechanism.
In light of the significant expenditures that would be associated with its smart meter deployment plans and related infrastructure upgrades, as well as its evaluation of recent PPUC decisions approving less-rapid deployment proposals by other utilities, WP re-evaluated its Act 129 compliance strategy, including both its plans with respect to smart meter deployment and certain smart meter dependent aspects of the EE&C Plan. In October 2010, WP and Pennsylvania’s Office of Consumer AdvocateOCA 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. The proposed settlement remains subject to review byOn May 3, 2011, the ALJ who will prepareissued an Initial Decision recommending that the PPUC approve the Amended Joint Petition for considerationFull Settlement. The PPUC approved the Initial Decision by the PPUC.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. TheOn April 29, 2011, the PPUC has not yet initiated that investigation.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.

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Virginia
In September 2010, PATH-VA filed an application with the Virginia SCCVSCC 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, by approximately $122.1 million annually, effective June 10, 2010. In January 2010, MP and PE filed supplemental testimony discussing a tax treatment change that would result in a revenue requirement approximately $7.7 million lower than the requirement included in the original filing. In addition, in December 2009, subsidiaries of MP and PE completed a securitization transaction to finance certain costs associated with the installation of scrubbers at the Fort Martin generating station, which costs would otherwise have been included in the request for rate recovery. Consequently,was amended through subsequent filings. MP and PE ultimately requested an annual increase in retail rates of approximately $95 million, rather than $122.1 million. In April 2010, MP and PE filed with the WVPSC a Joint Stipulation and Agreement of Settlement reached with the other parties in the proceeding that provided for:
a $40 million annualized base rate increase effective June 29, 2010;
a deferral of February 2010 storm restoration expenses in West Virginia over a maximum five-year period;
an additional $20 million annualized base rate increase effective in January 2011;
a decrease of $20 million in ENEC rates effective January 2011, which amount is deferred for later recovery in 2012; and
•an additional $20 million annualized base rate increase effective in January 2011;
•a decrease of $20 million in ENEC rates effective January 2011, which amount is deferred for later recovery in 2012; and
a moratorium on filing for further increases in base rates before December 1, 2011, except under specified circumstances.
The WVPSC approved the Joint Petition and Agreement of Settlement in June 2010.
In 2009, the West Virginia Legislature enacted the Alternative and Renewable Energy Portfolio Act (Portfolio Act), which generally requires that a specified minimum percentage of electricity sold to retail customers in West Virginia by electric utilities each year be derived from alternative and renewable energy resources according to a predetermined schedule of increasing percentage targets, including ten percent by 2015, fifteen percent by 2020, and twenty-five percent by 2025. In November 2010, the WVPSC issued Rules Governing Alternative and Renewable Energy Portfolio Standard (RPS Rules), which became effective on January 4, 2011. Under the RPS Rules, on or before January 1, 2011, each electric utility subject to the provisions of this rule was required to prepare an alternative and renewable energy portfolio standard compliance plan and file an application with the WVPSC seeking approval of such plan. MP and PE filed their combined compliance plan in December 2010. 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 Companiescompanies in meeting their combined requirements under the Portfolio Act. Further, in February 2011, MP and PE filed a petition with the WVPSC seeking an Order declaring that MP is entitled to all alternative &and renewable energy resource credits associated with the electric energy, or energy and capacity, that MP is required to purchase pursuant to electric energy purchase agreements between MP and three non-utility electric generating facilities in WV. The City of New Martinsville and Morgantown Energy Associates, each the owner of one of the contracted resources, has filed anparticipated in the case in opposition to the Petition.
FERC Matters
Rates for Transmission Service Between MISO and PJM
In November 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as SECA) during a 16-month transition period. In 2005, the FERC set the SECA for hearing. The presiding ALJ issued an initial decision in August 2006, rejecting the compliance filings made by MISO, PJM and the transmission owners, and directing new compliance filings. This decision was subject to review and approval by the FERC. In May 2010, FERC issued an order denying pending rehearing requests and an Order on Initial Decision which reversed the presiding ALJ’s rulings in many respects. Most notably, these orders affirmed the right of transmission owners to collect SECA charges with adjustments that modestly reduce the level of such charges, and changes to the entities deemed responsible for payment of the SECA charges. The Ohio Companies were identified as load serving entities responsible for payment of additional SECA charges for a portion of the SECA period (Green Mountain/Quest issue). FirstEnergy executed settlements with AEP, Dayton and the Exelon parties to fix FirstEnergy’s liability for SECA charges originally billed to Green Mountain and Quest for load that returned to regulated service during the SECA period. The AEP, Dayton and Exelon, settlements were approved by the FERC in November 2010, and the relevant payments made. The Utilitiessubsidiaries 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.

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PJM Transmission Rate
In April 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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FERC’s Opinion 494 order was appealed to the U.S. Court of Appeals for the Seventh Circuit, which issued a decision in August 2009. The court affirmed FERC’s ratemaking treatment for existing transmission facilities, but found that FERC had not supported its decision to allocate costs for 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 then reply comments on later dates. PJM filed certain studies with FERC on April 13, 2010, in response to the FERC order. PJM’s filing demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain eastern utilities in PJM bearing the majority of the costs. Numerous parties filed responsive comments or studies on May 28, 2010 and reply comments on June 28, 2010. FirstEnergy and a number of other utilities, industrial customers and state commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. 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 the 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 for moving its transmission rate into PJM’s tariffs. FirstEnergy expects ATSI to enter PJM on June 1, 2011, and that if legal proceedings regarding its rate are outstanding at that time, ATSI will be permitted to start charging its proposed rates, subject to refund. On April 1, 2011, the MISO Transmission Owners (including ATSI) filed proposed tariff language that describes the mechanics of collecting and administering MTEP costs from ATSI-zone ratepayers. From March 20, 2011 through April 1, 2011, FirstEnergy, PJM and the MISO submitted numerous filings for the purpose of effecting movement of the ATSI zone to PJM on June 1, 2011. These filings include clean-up ofamendments to the MISO’s tariffs (to remove the ATSI zone), submission of load and generation interconnection agreements to reflect the move into PJM, and submission of changes to PJM’s tariffs to support the move into PJM.
On May 31, 2011, FERC proceedings are pending in which ATSI’sissued orders that address the proposed ATSI transmission rate, and certain parts of the exit fee payable to MISO tariffs that reflect the mechanics of transmission cost allocationsallocation and collection. In its May 31, 2011 orders, FERC approved ATSI’s proposal to move the ATSI formula rate into the PJM tariff without significant change. Speaking to ATSI’s proposed treatment of the MISO’s exit fees and charges for transmission costs that were allocated to the ATSI zone, FERC required ATSI to present a cost-benefit study that demonstrates that the benefits of the move for transmission customers exceed the costs of any such move, which FERC had not previously required. Accordingly, FERC ruled that these costs must be removed from ATSI’s proposed transmission rates until such time as ATSI files and FERC approves the cost-benefit study. On June 30, 2011, ATSI submitted the compliance filing that removed the MISO exit fees and transmission cost allocation charges from ATSI’s proposed transmission rates. Also on June 30, 2011, ATSI requested rehearing of FERC’s decision to require a cost-benefit 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 and 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 are under review.MISO. ATSI did not and does not agree that these costs should be charged to ATSI but, in order to settle the case and all claims associated with the case, ATSI agreed to a one-time payment of $1.8 million to the MISO. This settlement agreement has been submitted for FERC’s review and approval. The final outcome of thesethose proceedings that address the remaining open issues related to ATSI’s move into PJM and their impact, if any, on FirstEnergy cannot be predicted.predicted at this time.
MISO Multi-Value Project Rule Proposal
In July 2010, MISO and certain MISO transmission owners jointly filed with FERC their proposed cost allocation methodology for certain new transmission projects. The new transmission projects—described as MVPs—MVPs — are a class of MTEP projects.transmission projects that are approved via MISO’s formal transmission planning process (the MTEP). The filing parties proposed to allocate the costs of MVPs by means of a usage-based charge that will be applied to all loads within the MISO footprint, and to energy transactions that call for power to be “wheeled through” the MISO as well as to energy transactions that “source” in the MISO but “sink” outside of MISO. The filing parties expect that the MVP proposal will fund the costs of large transmission projects designed to bring wind generation from the upper Midwest to load centers in the east. The filing parties requested an effective date for the proposal of July 16, 2011. On August 19, 2010, MISO’s Board approved the first MVP project — the “Michigan Thumb Project.” Under MISO’s proposal, the costs of MVP projects approved by MISO’s Board prior to the anticipated June 1, 2011 effective date of FirstEnergy’s integration into PJM would continue to be allocated to FirstEnergy. MISO estimated that approximately $15 million in annual revenue requirements would be allocated to the ATSI zone associated with the Michigan Thumb Project upon its completion.

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In September 2010, FirstEnergy filed a protest to the MVP proposal 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 integration into PJM, it would be unjust and unreasonable to allocate any MVP costs to the ATSI zone, or to ATSI. Numerous other parties filed pleadings on MISO’s MVP proposal.

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In December 2010, FERC issued an order approving the MVP proposal without significant change. FERC’s order was not clear, however, as to whether the MVP costs would be payable by ATSI or load in the ATSI zone. FERC stated that the MISO’s tariffs obligate ATSI to pay all charges that attachattached 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 usage-based, costs could not be applied to ATSI, which is a stand-alone transmission company that does not use the transmission system. FirstEnergy also renewed its arguments regarding cost causation and the impropriety of allocating costs to the ATSI zone or to ATSI.
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.
PJM Calculation Error
In March 2010, MISO filed two complaints at FERC against PJM relating to a previously-reported modeling error in PJM’s system that impacted the manner in which market-to-market power flow calculations were made between PJM and MISO since April 2005. MISO claimed that this error resulted in PJM underpaying MISO by approximately $130 million over the time period in question. Additionally, MISO alleged that PJM did not properly trigger market-to-market settlements between PJM and MISO during times when it was required to do so, which MISO claimed may have cost it $5 million or more. As PJM market participants, AE Supply and MP may be liable for a portion of any refunds ordered in this case. PJM, Allegheny and other PJM market participants filed responses to MISO complaints and PJM filed a related complaint at FERC against MISO claiming that MISO improperly called for market-to-market settlements several times during the same time period covered by the two MISO complaints filed against PJM, which PJM claimed may have cost PJM market participants $25 million or more. On January 4, 2011, an Offer of Settlement was filed at FERC that, if approved, would resolve all pending issues in the dispute. The Offer of Settlement calls for the withdrawal of all pending complaints with no payments being made by any parties. Initial comments on the Offer of Settlement were filed at FERC on January 24, 2011. FirstEnergy and Allegheny Energy filed comments supporting the proposed settlement. A report on the partially contested settlement was issued by the settlement judge to the FERC on March 9, 2011. On March 16, 2011, the settlement judge terminated the settlement proceedings and forwarded the partially contested settlement to the FERC for review. The case is awaiting a decision by the FERC.
California Claims Matters
In October 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the California Department of Water Resources (CDWR) during 2001. The settlement proposal claims that CDWR is owed approximately $190 million for these alleged overcharges. This proposal was made in the context of mediation efforts by the FERC and the United States Court of Appeals for the Ninth Circuit in pending proceedings to resolve all outstanding refund and other claims, including claims of alleged price manipulation in the California energy markets during 2000 and 2001. The Ninth Circuit has since remanded one of those proceedings to the FERC, which arises out of claims previously filed with the FERC by the California Attorney General on behalf of certain California parties against various sellers in the California wholesale power market, including AE Supply (the Lockyer case). AE Supply and several other sellers have filed motions to dismiss the Lockyer case. In March 2010, the judge assigned to the case entered an opinion that granted the motions to dismiss filed by AE Supply and other sellers and dismissed the claims of the California Parties. In April 2010, the California parties filed exceptions toOn May 4, 2011, FERC affirmed the judge’s ruling with the FERC, and briefing is complete on those exceptions. The parties are awaiting a ruling from the FERC on the exceptions.ruling.
In June 2009, the California Attorney General, on behalf of certain California parties, filed a second lawsuitcomplaint with the FERC against various sellers, including AE Supply (the Brown case), again seeking refunds for trades in the California energy markets during 2000 and 2001. The above-noted trades with CDWR are the basis for the joining ofincluding AE Supply in this new lawsuit.complaint. AE Supply has filed a motion to dismiss the Brown casecomplaint that is pending beforewas granted by FERC on May 24, 2011. On June 23, 2011, the FERC. No scheduling order has been entered inCalifornia Attorney General requested rehearing of the Brown case. Allegheny intends to vigorously defend against these claims butMay 24, 2011 order. FirstEnergy cannot predict their outcome.the outcome of this matter.
Transmission Expansion
TrAIL Project.TrAIL is a 500 kV transmission line currently under construction that will extendextending from southwest Pennsylvania through West Virginia and into northern Virginia. On April 15,Effective May 19, 2011, theall segments of TrAIL 500 kV line segment from Meadowbrook substation to Loudoun substation in Virginia was successfullywere energized and is carrying load. The other segments are planned to be energized in May. The entire TrAIL line is scheduled to be completed and placed in service no later than June 2011.service.
PATH Project.The PATH Project is comprised of a 765 kV transmission line that iswas proposed to extend from West Virginia through Virginia and into Maryland, modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland.

 

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PJM initially authorized construction of the PATH Project in June 2007 and, on June 17, 2010, requested that PATH, LLC proceed with all efforts related to the PATH Project, including state regulatory proceedings, assuming a required in-service date of June 1, 2015.2007. 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 potential need for the project as part of its continuing RTEP process. PJM stated that its action did not constitute a directive to FirstEnergy and AEP to cancel or abandon the PATH Project. PJM further stated that it will complete a more rigorous analysis of the PATH Project and other transmission requirements and its Board will review this comprehensive analysis as part of its consideration of the 2011 RTEP. On February 28, 2011, affiliates of FirstEnergy and AEP filed motions or notices to withdraw applications for authorization to construct the project that were pending before state commissions in West Virginia, Virginia and Maryland. Withdrawal was deemed effective upon filing the notice with the MDPSCMDPSC. The WVPSC and the WVPSC hasVSCC have granted the motion to withdraw. The VSCC has not ruled on the motionmotions 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 proceeding or whether it will have a material impact on its operating results.
Sales to Affiliates
FES has received authorization from the FERC to make wholesale power sales to affiliated regulated utilities in New Jersey, Ohio, and Pennsylvania. FES actively participates in auctions conducted by or on behalf the regulated affiliates to obtain power necessary to meet the utilities’ POLR obligations. AE Supply, a merchant affiliate acquired in the FirstEnergy-Allegheny merger, also participates in these auctions, and obtains prior FERC authorization when necessary to make sales to FE affiliates.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 SO2 and NOx emissions regulations under the CAA. FirstEnergy complies with SO2 and NOx reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, combustion controls and post-combustion controls, generating more electricity from lower-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, 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 in accordance with that agreement.
In July 2008, three complaints were filed against FGCO in the U.S. District Court for the Western District of Pennsylvania 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. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these 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. and the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999) and Met-Ed. Specifically, these suits allege that “modifications” at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR permitting in violation of the CAA’s PSD program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. In September 2009, the Court granted Met-Ed’s motion to dismiss New Jersey’s and Connecticut’s claims for injunctive relief against Met-Ed, but denied Met-Ed’s motion to dismiss the claims for civil penalties. The parties dispute the scope of Met-Ed’s indemnity obligation to and from Sithe Energy, and Met-Ed is unable to predict the outcome of this matter.
In January 2009, the EPA issued a NOV to GenOn 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 from 1988 to the present without preconstruction NSR permitting in violation of the CAA’s PSD program. In May 2010, the EPA issued a second NOV to Mission, Penelec, 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 to those included in the June 2008 NOV. On July 20, 2010, the states of New York and Pennsylvania provided Mission, Penelec, NYSEG and others that have had an ownership interest in the Homer City Power Station a notification that was required 60 days prior to filing a citizen suit under the CAA. In January 2011, the DOJ filed a complaint against Penelec in the U.S. District Court for the Western District of Pennsylvania seeking injunctive relief against Penelec based on alleged “modifications” at the Homer City Power Station between 1991 to 1994 without preconstruction NSR permitting in violation of the CAA’s PSD and Title V permitting programs. The complaint was also filed against the former co-owner, New York State Electric and Gas Corporation, and various current owners of the Homer City, Station, including EME Homer City Generation L.P. and affiliated companies, including Edison International. In January 2011, another complaint was filed against Penelec and the other entities described above in the U.S. District Court for the Western District of Pennsylvania seeking damages based on the Homer City Station’sCity’s air emissions as well as certification as a class action and to enjoin the Homer City Station from operating except in a “safe, responsible, prudent and proper manner.” Penelec believes the claims are without merit and intends to defend itself against the allegations made in the complaint, but, at this time, is unable to predict the outcome of this matter. In addition, the Commonwealth of Pennsylvania and the States of New Jersey and New York intervened and have filed separate complaints regarding the Homer City Station seeking injunctive relief and civil penalties. Mission 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 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 aan 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 electric generation facilities,coal-fired plants, which collectively include 22 electric generation units:units Albright, Armstrong, Fort Martin, Harrison, Hatfield’s Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island. The letter requested information under Section 114 of the CAAIsland to determine compliance with the CAA and related requirements, including potential application of the NSR standards under the CAA, which can require the installation of additional air emission control equipment when the major modification of an existing facility results in an increase in emissions. AE has provided responsive information to this and a subsequent request but is unable to predict the outcome of this matter.
In May 2004, AE, AE Supply, MP and WP received a Notice of Intent to Sue Pursuant to CAA §7604 from the Attorneys General of New York, New Jersey and Connecticut and from the PA DEP, alleging that Allegheny performed major modifications in violation of the PSD provisions of the CAA at the following West Virginia coal-fired facilities: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 generation facilitiescoal-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 facilitiesPlants in Pennsylvania. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. In May 2006, the District Court denied Allegheny’s motion to dismiss the amended complaint. In July 2006, the Court determined that discovery would proceed regarding liability issues, but not remedies. Discovery on the liability phase closed on December 31, 2007, and summary judgment briefing was completed during the first quarter of 2008. In November 2008, the District Court issued a Memorandum Order denying all motions for summary judgment and establishing certain legal standards to govern at trial. In December 2009, a new trial judge was assigned to the case, who then entered an order granting a motion to reconsider the rulings in the November 2008 Memorandum Order. In April 2010, the new judge issued an opinion, again denying all motions for summary judgment and establishing certain legal standards to govern at trial. TheA non-jury trial on liability only was held in September 2010. Plaintiffs filed their proposed findings of fact and conclusions of law in December 2010, Allegheny made its related filings in February 2011 and plaintiffs filed their responses in April 2011. The parties are awaiting a decision from the District Court, but there is no deadline for that decision.
In September 2007, Allegheny also received a NOV from the EPA alleging NSR and PSD violations under the CAA, as well as Pennsylvania and West Virginia state laws at the Hatfield’s Ferry and Armstrong generation facilitiesPlants in Pennsylvania and the Fort Martin and Willow Island generation facilitiescoal-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 power stationcoal-fired plant for NOX, SO2 and mercury, based on a PJM declaration that the stationplant is vital to reliability in the Baltimore/Washington DC metropolitan area, which PJM determined in 2006. Pursuant to the legislation, the Maryland Department of the Environment (MDE) passed alternate NOX and SO2 limits for R. Paul Smith, which became effective in April 2009. However, R. Paul Smith is still required to meet the Healthy Air Act mercury reductions of 80% beginning in 2010. The statutory exemption does not extend to R. Paul Smith’s CO2 emissions. Maryland issued final regulations to implement RGGI requirements in February 2008. Ten RGGI auctions have been held through the end of calendar year 2010. RGGI allowances are also readily available in the allowance markets, affording another mechanism by which to secure necessary allowances. On March 14, 2011, MDE requested PJM perform an analysis to determine if termination of operation at R. Paul Smith would adversely impact the reliability of electrical service in the PJM region under current system conditions. FirstEnergy is unable to predict the outcome of this matter.
In January 2010, the WVDEP issued a NOV for opacity emissions at Allegheny’s Pleasants generating facility.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 NOx and SO2 emissions in two phases (2009/2010 and 2015), ultimately capping SO2SO2 emissions in affected states to 2.5 million tons annually and NOx emissions to 1.3 million tons annually. In 2008, the U.S. Court of Appeals for the District of Columbia 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 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 NOx and SO2SO2 emissions in two phases (2012 and 2014), ultimately capping SO2SO2 emissions in affected states to 2.62.4 million tons annually and NOx emissions to 1.31.2 million tons annually. The EPA proposed a preferred regulatory approach thatCSAPR allows trading of NOx and SO2 emission allowances between power plants located in the same state and severely limits interstate trading of NOx and SO2 emission allowances. The EPA also requested comment on two alternative approaches—the first eliminates interstate trading of NOx and SO2 emission allowances and the second eliminates trading of NOx and SO2 emission allowances in its entirety. Depending on the actions taken by the EPA with respect to CATR, the proposed MACT regulations discussed below and any future regulations that are ultimately implemented,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
On March 16, 2011, the EPA released its MACT proposal to establish emission standards for mercury, hydrochloric acid and various metals for electric generating units. Depending on the action taken by the EPA and how any future regulations are ultimately implemented, FirstEnergy’s future cost of compliance with MACT regulations may be substantial and changes to FirstEnergy’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, in June 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, proposals to ensure that 10% of electricity used in the United States comes from renewable sources by 2012, to increase to 25% by 2025, to implement an economy-wide cap-and-trade program to reduce GHG emissions by 80% by 2050. Certain states, primarily the northeastern states participating in the RGGI and western states, led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.
In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that required FirstEnergy to measure 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. Until July 1, 2011, this emissions applicability threshold will only apply if PSD is triggered by non-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 that recognized the scientific view that the increase in global temperature should be below two degrees Celsius; includes 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 establishes the “Copenhagen Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. To the extent that they have become a party to the Copenhagen Accord, developed economies, such as the European Union, Japan, Russia and the United States, would commit to quantified economy-wide emissions targets from 2020, while developing countries, including Brazil, China and India, would agree to take mitigation actions, subject to their domestic measurement, reporting and verification.
In 2009, the U.S. Court of Appeals for the Second Circuit and the U.S. Court of Appeals for the Fifth Circuit reversed and remanded lower court decisions that had dismissed complaints alleging damage from GHG emissions on jurisdictional grounds. However, a subsequent ruling from the U.S. Court of Appeals for the Fifth Circuit reinstated the lower court dismissal of a complaint alleging damage from GHG emissions. These cases involve common law tort claims, including public and private nuisance, alleging that GHG emissions contribute to global warming and result in property damages. The U.S. Supreme Court granted a writ of certiorari to review the decision of the Second Circuit. Oral argument was held on April 19,On June 20, 2011, and a decision is expected by July 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.

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Clean Water Act
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy’s plants. In addition, the 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. In April 2009, the U.S. Supreme Court reversed one significant aspect of the Second Circuit’s opinion and decided that Section 316(b) of the 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. On March 28, 2011, the EPA released a new proposed regulation under Section 316(b) of the Clean Water Act generally requiring fish impingement to be reduced to a 12% annual average and studies to be conducted at the majority of our existing generating facilities to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic life. On July 19, 2011, the EPA extended the public comment period for the new proposed Section 316(b) regulation by 30 days but stated its schedule for issuing a final rule remains July 27, 2012. FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore power plant’s water intake channel to divert fish away from the plant’s water intake system. In November 2010, the Ohio EPA issued a 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 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 generation facility.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 September 13, 2011.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 has not acted onagreed with PA DEP’s recommendation. Ifrecommended sulfate impairment designation. PA DEP’s goal is to submit a final water quality standards regulation, incorporating the sulfate impairment designation is approved, Pennsylvaniafor EPA approval by May, 2013. PA DEP will then need to develop a TMDL limit for the river, a process that will take aboutapproximately five years. Based on the stringency of the TMDL, FirstEnergy may incur significant costs to reduce sulfate discharges into the Monongahela River from its Hatfield’s Ferry and Mitchell facilities in Pennsylvania and its Fort Martin facility in West Virginia.

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In October 2009, the WVDEP issued the water discharge permit for the Fort Martin generation facility. Similar to the Hatfield’s Ferry water discharge permit issued for the scrubber project, the Fort Martin permit imposes effluent limitations for TDS and sulfate concentrations. The permit also imposes temperature limitations and other effluent limits for heavy metals that are not contained in the Hatfield’s Ferry water permit. Concurrent with the issuance of the Fort Martin permit, WVDEP also issued an administrative order that sets deadlines for MP to meet certain of the effluent limits that are effective immediately under the terms of the permit. MP appealed the Fort Martin permit and the administrative order. The appeal included a request to stay certain of the conditions of the permit and order while the appeal is pending, which was granted pending a final decision on appeal and subject to WVDEP moving to dissolve the stay. The appeals have been consolidated. MP moved to dismiss certain of the permit conditions for the failure of the WVDEP to submit those conditions for public review and comment during the permitting process. An agreed-upon order that suspends further action on this appeal, pending WVDEP’s release for public review and comment on those conditions, was entered on August 11, 2010. The stay remains in effect during that process. The current terms of the Fort Martin permit would require MP to incur significant costs or negatively affect operations at Fort Martin. Preliminary information indicates an initial capital investment in excess of the capital investment that may be needed at Hatfield’s Ferry in order to install technology to meet the TDS and sulfate limits in the Fort Martin permit, which technology may also meet certain of the other effluent limits in the permit. Additional technology may be needed to meet certain other limits in the permit. MP intends to vigorously pursue these issues but cannot predict the outcome of these appeals.

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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.
In December 2009, in an advanced notice of public rulemaking, the EPA asserted that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. In May 2010, the EPA proposed two options for additional regulation of coal combustion residuals, including the option of regulation as a special waste under the EPA’s hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. FirstEnergy��sFirstEnergy’s future cost of compliance with any coal combustion residuals regulations that may be promulgated could be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the EPA or the states.
The Little 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 March 31,June 30, 2011, based on estimates of the total costs of cleanup, the Utility RegistrantsRegistrants’ proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $104$133 million (JCP&L — $69 million, TE — $1 million, CEI — $1 million, FGCO — $1 million and FirstEnergy — $32$61 million) have been accrued through March 31,June 30, 2011. Included in the total are accrued liabilities of approximately $64$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. 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. In November 2010, the Supreme Court issued an order denying Plaintiffs’ motion. The Court’s order effectively ends the class action attempt, and leaves only nine (9) plaintiffs to pursue their respective individual claims. The remaining individual plaintiffs have not takenyet to take any affirmative steps to pursue their individual claims.

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Nuclear Plant Matters
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of March 31,June 30, 2011, FirstEnergy had approximately $2 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. FirstEnergy provides an additional $15 million parental guarantee associated with the funding of decommissioning costs for these units. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy’s nuclear decommissioning trustsNDT fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy’s obligation to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the nuclear decommissioning trusts.NDT. The NRC issued guidance anticipating an increase in low-level radioactive waste disposal costs associated with the decommissioning of FirstEnergy’s nuclear facilities. On March 28, 2011, FENOC submitted its biennial report on nuclear decommissioning funding to the NRC. This submittal identified a total shortfall in nuclear decommissioning funding for Beaver Valley Unit 1 and Perry of approximately $92.5 million. This estimate encompasses the shortfall covered by the existing $15On June 24, 2011, FENOC submitted a $95 million parental guarantee. FENOC agreed to increase the parental guarantee to $95 million within 90 days of the submittal.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, thea 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 regardingchallenging 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) the cost of mitigating a severe accident mitigation alternatives at Davis-Besse. On May 6, 2011, FENOC is currently evaluating these developments and consideringfiled an appropriate response. appeal with the NRC Commissioners from the order granting a hearing on the Davis-Besse license renewal application.
On April 14, 2011, a group of environmental organizations petitioned the NRC Commissioners to suspend allcertain pending nuclear license renewallicensing 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 event 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 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
In February 2010, a class action lawsuit was filed in Geauga County Court of Common Pleas against FirstEnergy, CEI and OE seeking declaratory judgment and injunctive relief, as well as compensatory, incidental and consequential damages, on behalf of a class of customers related to the reduction of a discount that had previously been in place for residential customers with electric heating, electric water heating, or load management systems. The reduction in the discount was approved by the PUCO. In March 2010, the named-defendant companies filed a motion to dismiss the case due to the lack of jurisdiction of the court of common pleas. The court granted the motion to dismiss on September 7, 2010. The plaintiffs appealed the decision to the Court of Appeals of Ohio, 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 12 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, 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, 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 under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Earnings available to parentNet income decreased by $44$158 million in the first threesix months of 2011 compared to the same period of 2010. The decrease was primarily due to increased transmission expenses,lower sales margin, an inventory valuationreserve adjustment, non-core asset impairments and the effect of mark-to-market accounting.adjustments.
Revenues
Total revenues increased $3decreased $30 million, or 1%, in the first threesix months of 2011, compared to the same period of 2010, primarily due to reduced POLR and structured sales, partially offset by growth in direct and governmentgovernmental aggregation sales, partially offset by decreases in POLR sales.
The increasedecrease in revenues resulted from the following sources:
                        
 Three Months    Six Months   
 Ended March 31 Increase  Ended June 30 Increase 
Revenues by Type of Service 2011 2010 (Decrease)  2011 2010 (Decrease) 
 (In millions)  (In millions) 
Direct and Government Aggregation $840 $512 $328 
POLR 369 673  (304)
Other Wholesale 96 91 5 
Direct and Governmental Aggregation $1,765 $1,097 $668 
POLR and Structured Sales 607 1,315  (708)
Wholesale 156 142 14 
Transmission 26 17 9  56 36 20 
RECs 32 67  (35) 44 67  (23)
Other 28 28 —  56 57  (1)
              
Total Revenues
 $1,391 $1,388 $3  $2,684 $2,714 $(30)
              
                        
 Three Months    Six Months   
 Ended March 31 Increase  Ended June 30 Increase 
MWH Sales by Type of Service 2011 2010 (Decrease)  2011 2010 (Decrease) 
 (In thousands)  (In thousands) 
Direct 9,671 5,854  65.2% 21,219 12,857  65.0%
Government Aggregation 4,310 2,732  57.8%
POLR 5,714 13,276  (57.0)%
Governmental Aggregation 8,279 5,447  52.0%
POLR and Structured Sales 9,561 25,344  (62.3)%
Wholesale 1,113 898  23.9% 1,380 1,538  (10.3)%
              
Total Sales
 20,808 22,760  (8.6)% 40,439 45,186  (10.5)%
              

 

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The increase in direct and governmentgovernmental aggregation revenues of $328$668 million resulted from the acquisition of new commercial and industrial customers andas well as new governmentgovernmental aggregation contracts with communities in Ohio in addition, salesthat provided generation to approximately 1.5 million residential and small commercial customers were bolstered by weather inat the delivery area that was 5.2% colder than inend of June 2011 compared to approximately 1.1 million customers at the end of June 2010.
The decrease in POLR revenues of $304$708 million was due to lower sales volumes to Met-Ed and Penelec, primarily due to the Pennsylvaniaabsence in 2011 of a 1,300 MW third-party contract associated with serving Met-Ed and Penelec, and reduced sales to the Ohio Companies, partially offset by increased sales to non-associated companies and higher unit prices to the Pennsylvania Companies.Companies consistent with our business strategy. Participation in POLR auctions and RFPs are expected to continue but the concentrationproportion of these sales will primarily be dependentdepend on our success in ourhedge positions for direct retail and aggregation sales channels.sales.
Wholesale revenues increased $5by $14 million due to increased volumeshigher wholesale prices partially offset by lower wholesale prices.decreased volumes. The higherlower sales volumes were the result of increased short termdecreased short-term (net hourly position)positions) transactions in MISO. $22 million of wholesale revenue resulted from long positions in MISO thatAdditional capacity revenues earned by generating units were unable to be netted with short positions in PJM, due to separate settlement requirements within each RTO.partially offset 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 $223  $493 
Change in prices  (4)  (20)
      
 219  473 
      
Government Aggregation: 
 
Governmental Aggregation: 
Effect of increase in sales volumes 100  176 
Change in prices 9  19 
      
 109  195 
      
Net Increase in Direct and Government Aggregation Revenues
 $328 
Net Increase in Direct and Governmental Aggregation Revenues
 $668 
      
 
 Increase 
Source of Change in POLR Revenues (Decrease) 
 (In millions) 
POLR: 
Effect of decrease in sales volumes $(384)
Change in prices 80 
   
  (304)
   
 
 Increase 
Source of Change in Wholesale Revenues (Decrease) 
 (In millions) 
Wholesale: 
Effect of increase in sales volumes 12 
Change in prices  (7)
   
 5 
   
     
  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 increase in sales volumes $(15)
Change in prices  29 
    
  $14 
    
Transmission revenues increased $9by $20 million due primarily to higher MISO and PJM congestion revenues.revenue. The revenues derived from the sale of RECs declined $35$23 million in the first quartersix months of 2011.
Expenses
Total operating expenses increased $81by $199 million in the first threesix months of 2011, compared with the same period of 2010.

 

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The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first threesix months of 2011, 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 decreased unit costs $(22)
Change due to increased unit costs $2 
Change due to volume consumed 31   (29)
   
     (27)
 9    
    
Nuclear Fuel:  
Change due to increased unit costs 6  14 
Change due to volume consumed —  1 
      
 6  15 
      
 
Non-affiliated Purchased Power:  
Change due to increased unit costs 32  108 
Change due to volume purchased  (185)  (242)
   
     (134)
  (153)   
    
Affiliated Purchased Power:  
Change due to increased unit costs 20  34 
Change due to volume purchased  (12)  (30)
      
 8  4 
      
Net Decrease in Fuel and Purchased Power Costs
 $(130) $(142)
      
FossilTotal fuel costs increased $9decreased by $12 million in the first threesix months of 2011, compared to the same period of 2010, as a result of higherreduced generation at the fossil units, partially offset by decreasedhigher fossil unit costs. Fossil unit prices declinedincreased primarily due to improved generating unit availability at more efficient units, partially offset by increased coal transportation costs. Nuclear fuel expenses increased primarily due to higher unit prices following the refueling outages that occurred in 2010.
Non-affiliated purchased power costs decreased $153by $134 million in the first six months of 2011, compared to the same period of 2010, due primarily 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 partythird-party contract associated with serving Met-Ed and Penelec. $35 millionPenelec in the first half of 2011. Affiliated purchased power expense resulted from long positions in MISO that were unable to be netted with short positions in PJM, due to separate settlement requirements within each RTO.
Other operating expensescosts increased $191by $4 million in the first threesix months of 2011, compared to the same period of 2010, as a result of increased RTO transmission costs ($111 million), an inventory valuation adjustment ($54 million) and increased nuclear operating costs ($15 million) relateddue to higher laborunit 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 period of 2010 due to the following:
Transmission expenses increased by $176 million due primarily to increases in PJM of $198 million from higher congestion, network, and related benefits,line loss expense, partially offset by lower professionalMISO transmission expenses of $22 million.
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 2010 was largely capital-related.
Fossil operating costs increased by $20 million due primarily to higher labor, contractor costs.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 three month of 2011, impairmentAllegheny merger.
Impairment charges of long-lived assets increased expenses by $14 million.$18 million due to impairments at certain non-core peaking facilities during the first six months of 2011.
General taxes increased $2by $11 million due to an increase in revenue-related taxes.
Other Expense
Total other expense decreased $9increased by $17 million in the first threesix months of 2011, compared to the same period of 2010, primarily due to an increasea decrease in miscellaneous income ($16 million) and increased investment income ($5 million), partially offset by an increase in interest expense (net of capitalized interest — $12($24 million). Increased miscellaneous income was the result of mark-to-market adjustments on power related derivatives. Increased investment income was the result of higher nuclear decommissioning trust investment income. The increase in interest expense was the result of reduced capitalized interest associated with the completion of the Sammis AQC project in 2010, combined withpartially offset by increased interest expense associated with the restructuring of certain variable rate PCRBs into fixed rate modes.investment income ($8 million) from higher NDT income.

 

119133

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 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 decreased by $6$5 million in the first threesix months of 2011, compared to the same period of 2010. The decrease primarily resulted from lower revenues and higher other operating costs,expenses, partially offset by lower purchased power costs and amortization of regulatory assets.
Revenues
Revenues decreased $116by $171 million, or 23%18%, in the first threesix months of 2011, compared with the same period in 2010, due primarily to a decrease in generation revenues, partially offset by higher distribution and wholesale generation revenues.
Distribution revenues increased $10by $31 million in the first threesix months of 2011, compared to the same period in 2010, primarily 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 influenceddriven by increased weather-related usage in the first threesix months of 2011, reflecting a 5%6% increase in heating degree daysdays. 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 threesix months of 2011, compared to the same period in 2010, are summarized in the following tables:
     
Distribution KWH Deliveries Increase 
     
Residential  1.43.0%
Commercial  1.20.2%
Industrial  9.33.5%
    
Increase in Distribution Deliveries
  3.72.4%
    
        
Distribution Revenues Increase  Increase 
 (In millions)  (In millions) 
Residential $7  $19 
Commercial 1  7 
Industrial 2  5 
      
Increase in Distribution Revenues
 $10  $31 
      
Retail generation revenues decreased $127by $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 increased customer shopping, partially offset by increased weather-related usage in the first threesix months of 2011, as described above. The increase in customer shopping for residential, commercial and industrial customer classes was 23%, 14% and 8%, respectively.

 

120134

ChangesDecreases in retail generation KWH sales and revenues in the first threesix months of 2011, compared to the same period in 2010, are summarized in the following tables:
     
Retail Generation KWH Sales Decrease 
     
Residential  (33.030.7)%
Commercial  (43.239.0)%
Industrial  (16.325.4)%
    
Decrease in Retail Generation Sales
  (32.031.2)%
    
        
Retail Generation Revenues Decrease  Decrease 
 (In millions)  (In millions) 
Residential $(85) $(128)
Commercial  (30)  (52)
Industrial  (12)  (31)
      
Decrease in Retail Generation Revenues
 $(127) $(211)
      
Wholesale revenues increased by $15 million in the first six months of 2011, compared to the same period of 2010, due to higher revenues from sales to NGC from OE’s leasehold interests in Perry Unit 1 and Beaver Valley Unit 2.
Expenses
Total expenses decreased $108by $171 million in the first threesix months of 2011, compared to the same period of 2010. The following table presents changes from the prior period by expense category:
        
 Increase  Increase 
Expenses — Changes (Decrease) 
Expenses - Changes (Decrease) 
 (In millions)  (In millions) 
Purchased power costs $(94) $(175)
Other operating expenses 13  36 
Amortization of regulatory assets, net  (29)  (36)
General taxes 2  4 
      
Net Decrease in Expenses
 $(108) $(171)
      
Purchased power costs decreased in the first threesix months of 2011, compared to the same period of 2010, primarily due to lower KWH purchases resulting from reduced generation sales requirements in the first threesix months of 2011 coupled with lower unit costs. The increase in other operating costsexpenses for the first threesix months of 2011 was primarilyprincipally due to expenses associated with the 2011refueling outages at OE’s leased Perry and Beaver Valley Unit 2 refueling outage that were absent in 2010. The amortization of regulatory assets decreased primarily due to higher deferred residential generation credits in 2011. General taxes increased as a result of higher property taxes.
Other Expense
Other expense increased by $3 million in the first six months of 2011, compared to the same period of 2010 due to lower nuclear decommissioning trust investment income.

 

121135

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 decreased by $1 millionslightly in the first threesix months of 2011, compared to the same period of 2010. The decrease in earnings was primarily due to lower revenues, partially offset by lower purchased power and amortization of regulatory assets.
Revenues
Revenues decreased $105by $183 million, or 32%29%, in the first threesix months of 2011, compared to the same period of 2010, due to lower retail generation and distribution revenues.
Distribution revenues decreased $5by $14 million in the first threesix months of 2011, compared to the same period of 2010, due to lower average unit prices for the industrialresidential and residentialindustrial customer classes, partially offset by increased KWH deliveries across all sectors.to the residential and commercial customer classes. The lower average unit prices were the result of the absence of transition charges in 2011. Higher KWH deliveries into the residential class were influenceddriven by increased weather-related usage in the first threesix months of 2011, reflecting a 10%15% increase in heating degree days in CEI’s service territory. Lower distribution deliveries to industrial customers reflected softer economic conditions in this sector.
Changes in distribution KWH deliveries and revenues in the first threesix months of 2011, compared to the same period of 2010, are summarized in the following tables:
     
Increase
Distribution KWH Deliveries Increase(Decrease) 
     
Residential  2.32.2%
Commercial  3.12.9%
Industrial  0.9(3.1)%
    
Increase in Distribution Deliveries
  2.10.6%
    
        
 Increase  Increase 
Distribution Revenues (Decrease)  (Decrease) 
 (In millions)  (In millions) 
Residential $—  $2 
Commercial 7  17 
Industrial  (12)  (33)
      
Net Decrease in Distribution Revenues
 $(5) $(14)
      

 

122136

Retail generation revenues decreased $101by $169 million in the first threesix months of 2011, compared to the same period of 2010, primarily due to lower KWH sales in all customer classes and lower average unit prices across allfor 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 threesix months of 2011, partially offset by higherthe impact of increased weather-related usage by residential KWH deliveries resulting from the colder weather conditions.customers as described above. Lower average unit prices in the residential customer class were the result of generation credits in place for 2011.
ChangesDecreases in retail generation sales and revenues in the first threesix months of 2011, compared to the same period of 2010, are summarized in the following tables:
     
Retail Generation KWH Sales Decrease 
     
Residential  (48.446.6)%
Commercial  (48.344.2)%
Industrial  (62.869.8)%
    
Decrease in Retail Generation Sales
  (53.355.0)%
    
        
Retail Generation Revenues Decrease  Decrease 
 (In millions)  (In millions) 
Residential $(46) $(69)
Commercial  (29)  (46)
Industrial  (26)  (54)
      
Decrease in Retail Generation Revenues
 $(101) $(169)
      
Expenses
Total expenses decreased $98by $173 million in the first threesix months of 2011, compared to the same period of 2010. The following table presents the change from the prior period by expense category:
        
 Increase  Increase 
Expenses — Changes (Decrease) 
Expenses - Changes (Decrease) 
 (In millions)  (In millions) 
Purchased power costs $(82) $(155)
Other operating costs 4  6 
Amortization of regulatory assets, net  (22)  (34)
General taxes 2  10 
      
Net Decrease in Expenses
 $(98) $(173)
      
Purchased power costs decreased in the first threesix months of 2011 due to lower KWH purchases resulting from reduced sales requirements in the first threesix months of 2011. Other operating expenses increased principally due to 2011 inventory valuation adjustments. Decreased amortization of regulatory assets was primarily due to the completion of transition cost recovery at the end of 2010 and 2011 and deferred residential generation credits in 2011, partially offset by increased recovery of non-residentialdeferred distribution deferralscosts and the absence in 20102011 of deferred renewable energy credit expenses.expenses that were deferred in 2010. General taxes increased in the first threesix months of 2011 due to increased property taxes in 2011.as compared to the same period of 2010.

 

123137

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 decreasedincreased by $2$3 million in the first threesix months of 2011, compared to the same period of 2010. The decreaseincrease primarily resulted from lower purchased power costs and higher cost deferrals, partially offset by lower revenues and higher other operating costs, partially offset by lower purchased power costs and deferral of regulatory assets.expenses.
Revenues
Revenues decreased $19by $40 million, or 14%16%, in the first threesix months of 2011, compared to the same period of 2010, due to a decrease in retail generation revenues, partially offset by higher distribution revenues and wholesale generation revenues.
Distribution revenues increased $2by $3 million in the first threesix months of 2011, compared to the same period of 2010, due to higher residential and industrial revenues, partially offset by lower commercialindustrial revenues. Residential and industrial revenues were the result of higher KWH deliveries and average unit prices and higher KWH deliveries.prices. The higher KWH deliveries in the residential class were influenceddriven by increased weather-related usage in the first threesix months of 2011, reflecting a 9%14% increase in heating degree days, partially offset by a 23% decrease in cooling degree days in TE’s service territory. CommercialIndustrial revenues were impacted by lower average unit prices, partially offset by higher KWH deliveries and lower average unit prices.from recovering economic conditions.
Changes in distribution KWH deliveries and revenues in the first threesix months of 2011, compared to the same period of 2010, are summarized in the following tables:
     
  Increase 
Distribution KWH Deliveries (Decrease) 
     
Residential  3.64.5%
Commercial  (2.32.5)%
Industrial  5.33.7%
    
Net Increase in Distribution Deliveries
  3.32.6%
    
        
 Increase  Increase 
Distribution Revenues (Decrease)  (Decrease) 
 (In millions)  (In millions) 
Residential $2  $5 
Commercial  (1) — 
Industrial 1   (2)
      
Net Increase in Distribution Revenues
 $2  $3 
      
Retail generation revenues decreased $25by $53 million in the first threesix months of 2011, compared to the same period of 2010, due to lower KWH sales to all customer classes and lower unit prices to residential and industrial customers.for all customer classes. Retail generation obligations are attributable to non-shopping customers and are procured through full-requirements auctions. TE defers the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings. Lower KWH sales were the result of increased customer shopping, partially offset by increased weather-related usage in the first three months of 2011, as described above. Customer shopping has increased for residential, commercial and industrial classes by 16%, 13% and 5%, respectively.

 

124138

ChangesDecreases in retail generation KWH sales and revenues in the first threesix months of 2011, compared to the same period of 2010, are summarized in the following tables:
     
Retail Generation KWH Sales Decrease 
     
Residential  (28.528.3)%
Commercial  (49.546.6)%
Industrial  (13.111.7)%
    
Decrease in Retail Generation Sales
  (24.022.6)%
    
        
Retail Generation Revenues Decrease  Decrease 
 (In millions)  (In millions) 
Residential $(10) $(16)
Commercial  (6)  (13)
Industrial  (9)  (24)
      
Decrease in Retail Generation Revenues
 $(25) $(53)
      
Wholesale revenues increased $3by $9 million in the first threesix months of 2011, compared to the same period of 2010, primarily due to higher revenues from sales to NGC from TE’s leasehold interest in Beaver Valley Unit 2.
Expenses
Total expenses decreased $15by $42 million in the first threesix months of 2011, compared to the same period of 2010. The following table presents changes from the prior period by expense category:
        
 Increase  Increase 
Expenses — Changes (Decrease) 
Expenses - Changes (Decrease) 
 (In millions)  (In millions) 
Purchased power costs $(24) $(53)
Other operating expenses 11  18 
Deferral of regulatory assets, net  (3)  (8)
General Taxes 1  1 
      
Net Decrease in Expenses
 $(15) $(42)
      
Purchased power costs decreased in the first threesix months of 2011, compared to the same period of 2010, due to lower KWH purchases resulting from reduced generation sales requirements in the first threesix months of 2011 coupled with lower unit costs. The increase in other operating costs for the first threesix months of 2011 was primarily due to expenses associated with the 2011 refueling outage at the leased Beaver Valley Unit 2 refueling outage thatand an Ohio Supreme Court decision rendered in the second quarter of 2011 favoring a large industrial customer, both of which were absent in 2010 and higher storm restoration expenses.2010. The deferral of regulatory assets increasedreduced expenses due to higher PUCO-approved cost deferrals in the first threesix months of 2011, compared to the same period of 2010.
Other Expense
Other expense increased by $2 million in the first six months of 2011, compared to the same period of 2010, due to lower nuclear decommissioning trust investment income.

 

125139

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, Market Risk Information, Credit Risk, Outlook Regulatory Matters, Environmental Matters, Other Legal Proceedings and New Accounting Standards and Interpretations.
Results of Operations
Net income decreased by $10$18 million in the first threesix months of 2011, compared to the same period of 2010. The decrease was primarily due to lower revenues, partially offset by reductions in purchased power costs, other operating costs and increased net amortization of regulatory assets, partially offset by lower purchased power costs and other operating costs.assets.
Revenues
InRevenues decreased by $190 million, or 13%, in the first threesix months of 2011 revenues decreased $57 million, or 8%, compared to the same period of 2010. The decrease in revenues was primarily due to lower distribution and retail generation revenues, partially offset by an increase in wholesale generation and other revenues.
Distribution revenues decreased $17by $71 million in the first threesix months of 2011, compared to the same period of 2010, primarily due to aan NJBPU-approved rate adjustment whichthat became effective March 1, 2011, for all customer classes, partially offset by higherclasses. The lower KWH deliveries into the residential class resulting fromwere influenced by decreased weather-related usage in the first six months of 2011, reflecting a 6%16% decrease in cooling degree days offsetting a 7% increase in heating degree days.days in JCP&L’s service territory. Lower distribution deliveries to commercial and industrial customers reflected soft economic conditions in these sectors.
ChangesDecreases in distribution KWH deliveries and revenues in the first threesix months of 2011 compared to the same period of 2010 are summarized in the following tables:
     
Increase
Distribution KWH Deliveries (Decrease)Decrease 
     
Residential  1.4(2.5)%
Commercial  (3.43.3)%
Industrial  (2.01.8)%
    
Net Decrease in Distribution Deliveries
  (1.12.7)%
    
        
Distribution Revenues Decrease  Decrease 
 (In millions)  (In millions) 
Residential $(5) $(33)
Commercial  (10)  (31)
Industrial  (2)  (7)
      
Decrease in Distribution Revenues
 $(17) $(71)
      
Retail generation revenues decreased $47by $132 million due to lower retail generation KWH sales in all customer classes.classes 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 difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings. These lower sales were primarily due to an increase in customer shopping.

 

126140

ChangesDecreases in retail generation KWH sales and revenues in the first threesix months of 2011, compared to the same period of 2010, are summarized in the following tables:
     
Retail Generation KWH Sales Decrease 
     
Residential  (7.512.1)%
Commercial  (26.426.2)%
Industrial  (23.124.8)%
    
Decrease in Retail Generation Sales
  (13.716.7)%
    
        
Retail Generation Revenues Decrease  Decrease 
 (In millions)  (In millions) 
Residential $(15) $(68)
Commercial  (29)  (59)
Industrial  (3)  (5)
      
Decrease in Retail Generation Revenues
 $(47) $(132)
      
Wholesale generation revenues increased $3by $6 million in the first threesix months of 2011, compared to the same period of 2010, due primarily to an increase in sales volumes.PJM spot market energy sales.
Other revenues increased $4by $8 million in the first threesix months of 2011, compared to the same period of 2010, primarily due to an increaseincreases in PJM network transmission revenues and transition bond revenues as a result of higher KWH deliveries to residential customers.revenues.
Expenses
Total expenses decreased $43by $163 million in the first threesix months of 2011, compared to the same period of 2010. The following table presents changes from the prior period by expense category:
        
 Increase  Increase 
Expenses — Changes (Decrease) 
Expenses - Changes (Decrease) 
 (In millions)  (In millions) 
Purchased power costs $(44) $(126)
Other operating costs  (9)  (6)
Provision for depreciation  (3)  (3)
Amortization of regulatory assets, net 12   (29)
General taxes 1  1 
      
Net Decrease in Expenses
 $(43) $(163)
      
Purchased power costs decreased by $126 million in the first threesix months of 2011 primarily due to lower requirements from reduced retail generation sales. Other operating costs decreased by $6 million in the first threesix months of 2011 primarily due toprincipally from lower storm restoration costs, partially offset by inventory valuation adjustments.costs. The amortization of regulatory assets increased primarilydecreased by $29 million due to reduced cost recovery under the NJBPU-approved NUG tariffs that became effective March 1, 2011, partially offset by lower storm cost deferrals and the write-off of nonrecoverable NUG costs, partially offset by lower purchased power deferrals in the first quarter of 2011.costs.

 

127141

METROPOLITAN EDISON COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
Met-Ed is a wholly owned electric utility subsidiary of FirstEnergy. Met-Ed conducts business in eastern Pennsylvania, providing regulated electric transmission and distribution services. Met-Ed also procures generation service for those customers electing to retain Met-Ed as their power supplier. In 2011, Met-Ed procures power 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 repurchased 118,595returned $150 million of capital to FirstEnergy Corp. on May 31, 2011, the sole owner of all of the shares of itsMet-Ed’s common stock from its parent, FirstEnergy, for $150 million on January 28, 2011.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 Capital Resources and Liquidity, Regulatory Matters, Environmental Matters, Other Legal Proceedings and New Accounting Standards and Interpretations.
Results of Operations
Net income increased by $10 million in the first threesix months of 2011, compared to the same period of 2010. The increase was primarily due to decreased purchased power, other operating expenses and amortization of net regulatory assets partially offset by decreased revenues.
Revenues
Revenue decreased $116by $279 million, or 24%30%, in the first threesix months of 2011 compared to the same period of 2010, reflecting lower distribution, retail generation, wholesale generation and transmission revenues, partially offset by an increase in retail generation revenues.
Distribution revenues decreased $72by $154 million in the first threesix months of 2011, compared to the same period of 2010, primarily due to lower rates resulting from the DSP that began in 2011 that eliminated the transmission component from the distribution rate. Higher KWH deliveries to industrial customers were due to improving economic conditions in Met-Ed’s service territory. Higher residential and commercialSlightly higher KWH deliveries reflect increased weather-related usage due to an 8% increase in heating degree days offsetting a 15% decrease in cooling degree days in the first threesix months of 2011, compared to the same period in 2010.
Changes in distribution KWH deliveries and revenues in the first three months of 2011, compared to the same period of 2010, are summarized in the following tables:
Distribution KWH DeliveriesIncrease
Residential3.4%
Commercial2.5%
Industrial5.8%
Increase in Distribution Deliveries
4.1%
     
Distribution Revenues Decrease 
  (In millions) 
Residential $(29)
Commercial  (17)
Industrial  (26)
    
Decrease in Distribution Revenues
 $(72)
    
Retail generation revenues increased $18 million in the first three months of 2011 compared to the same period of 2010, due to an increase in generation rates from the auctions and now including transmission services in the rates under the DSP effective January 1, 2011. The DSP resulted in higher composite unit prices across all customer classes. Higher KWH sales to residential customers were primarily due to weather-related usage as described above. Increased customer shopping in the commercial and industrial classes of 36% and 81%, respectively, reduced KWH sales to these classes. Retail generation obligations are attributable to non-shopping customers and are procured through full-requirements auctions. Met-Ed defers the difference between retail generation revenues and costs, resulting in no material effect to current period earnings.

128

Changes in retail generation KWH sales and revenues in the first threesix months of 2011, compared to the same period of 2010, are summarized in the following tables:
     
  Increase 
Retail GenerationDistribution KWH SalesDeliveries (Decrease) 
     
Residential  2.70.2%
Commercial  (34.14.1)%
Industrial3.6%
Net Increase in Distribution Deliveries
0.5%
     
Distribution Revenues Decrease 
  (In millions) 
Residential $(58)
Commercial  (47)
Industrial  (49)
    
Decrease in Distribution Revenues
 $(154)
    
Retail generation revenues decreased by $10 million in the first six months of 2011 compared to the same period of 2010, due to lower KWH sales to all customer classes resulting from increased customer shopping. Customer shopping has increased for residential, 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 inclusion of transmission services under the DSP, effective January 1, 2011, for all customer classes. Retail generation obligations are attributable to non-shopping customers and are procured through full-requirements auctions. In 2011, Met-Ed began deferring the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings.

142

Changes in retail generation KWH sales and revenues in the first six months of 2011, compared to the same period of 2010, are summarized in the following tables:
Retail Generation KWH SalesDecrease
Residential(1.0)%
Commercial(44.7)%
Industrial  (80.087.6)%
    
Net Decrease in Retail Generation Sales
  (34.543.1)%
    
        
 Increase  Increase 
Retail Generation Revenues (Decrease)  (Decrease) 
 (In millions)  (In millions) 
Residential $53  $88 
Commercial 3   (14)
Industrial  (38)  (84)
      
Net Increase in Retail Generation Revenues
 $18 
Net Decrease in Retail Generation Revenues
 $(10)
      
Wholesale revenues decreased $54by $105 million in the first threesix months of 2011 compared to the same period of 2010 primarily due to Met-Ed ending certain capacity purchase for resale contracts.
Transmission revenues decreased $8by $11 million in the first threesix months of 2011 compared to the same period of 2010 primarily due to decreased FTR 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 decreased $121$290 million in the first threesix months of 2011 compared to the same period of 2010. The following table presents changes from the prior year by expense category:
     
Expenses — Changes Decrease 
  (In millions) 
Purchased power costs $(50)
Other operating costs  (54)
Amortization of regulatory assets, net  (17)
    
Decrease in Expenses
 $(121)
    
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 decreased $50by $149 million in the first threesix months of 2011 due to a decrease in KWH purchased to source generation sales requirements, partially offset by higher unit costs. Other operating costs decreased $54$95 million in the first threesix months of 2011 compared to the same period in 2010 primarily due to lower transmission congestion and transmission loss expenses that are now included in the cost of purchased power (see reference to deferral accounting above). partially offset by increased costs for energy efficiency programs. The amortization of regulatory assets decreased $17$43 million in the first threesix months of 2011 primarily due to the termination of transmission and 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 threesix months of 2011, interest income decreased by $2 million due to reduced CTC stranded asset balances compared to the same period of 2010.

 

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PENNSYLVANIA ELECTRIC COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts business in northern and south central Pennsylvania, providing regulated electric transmission and distribution services. Penelec also procures generation service for those customers electing to retain Penelec as their power supplier. Beginning in 2011, Penelec procures power 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.
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, Market Risk Information, Credit Risk, Outlook Regulatory Matters, Environmental Matters, Other Legal Proceedings and New Accounting Standards and Interpretations.
Results of Operations
Net income increased slightlyby $2 million in the first threesix months of 2011, compared to the same period of 2010. The increase was primarily due to lower purchased power and other operating costs, partially offset by lower revenues and higher net amortization of regulatory assets and higher general taxes.assets.
Revenues
RevenueRevenues decreased $79by $193 million, or 19.5%25%, in the first threesix months of 2011 compared to the same period of 2010. The decrease in revenue was primarily due to lower distribution revenues, retail and wholesale generation revenues, and lower transmission revenues, partially offset by higher distribution revenues.
Distribution revenues increaseddecreased by $1$5 million in the first threesix months of 2011, compared to the same period of 2010, primarily due to an increaselower rates resulting from the DSP that began in 2011 that eliminated the retail transition rates and energy efficiency rates for all customer classes,transmission component from the distribution rate, partially offset by decreaseda PPUC approved rate adjustment for NUG costs. Higher KWH salesdeliveries 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 classes.customers in the first six months of 2011 reflected lower weather-related usage as cooling degree days were 10% below the same period in 2010.
Changes in distribution KWH deliveries and revenues in the first threesix months of 2011, compared to the same period of 2010, are summarized in the following tables:
     
  Increase 
Distribution KWH Deliveries (Decrease) 
     
Residential  (0.21.2)%
Commercial  (3.04.7)%
Industrial  10.07.3%
    
Net Increase in Distribution Deliveries
  3.11.4%
    
        
 Increase  Increase 
Distribution Revenues (Decrease)  (Decrease) 
 (In millions)  (In millions) 
Residential $3  $3 
Commercial  (5)  (14)
Industrial 3  6 
      
Net Increase in Distribution Revenues
 $1 
Net Decrease in Distribution Revenues
 $(5)
      
Retail generation revenues decreased $22by $80 million in the first threesix months of 2011, compared to the same period of 2010, primarily due to lower KWH sales tofor 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. Retail generation obligations are attributable to non-shopping customers and are procured through full-requirements auctions. In 2011, Penelec defersbegan deferring the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings. Lower sales to all customer classes were primarily due to an increase in customer shopping following the expiration of generation rate caps at the end of 2010. Higher generation rates reflect the inclusion of transmission services in generation rates under the DSP, effective January 1, 2011.

 

130144

Changes in retail generation KWH sales and revenues in the first threesix months of 2011, compared to the same period of 2010, are summarized in the following tables:
     
Retail Generation KWH Sales Decrease 
     
Residential  (0.42.7)%
Commercial  (38.347.1)%
Industrial  (78.587.4)%
    
Decrease in Retail Generation Sales
  (39.147.5)%
    
        
 Increase  Increase 
Retail Generation Revenues (Decrease)  (Decrease) 
 (In millions)�� (In millions) 
Residential $31  $52 
Commercial  (9)  (35)
Industrial  (44)  (97)
      
Net Decrease in Retail Generation Revenues
 $(22) $(80)
      
Wholesale generation revenues decreased $49by $98 million in the first threesix months of 2011, compared to the same period of 2010, due to Penelec no longer purchasing non-NUG capacity for resale to the PJM market beginning in 2011.
Transmission revenues decreased $8by $11 million in the first threesix months of 2011, compared to the same period of 2010, primarily due to lower Financial Transmission Rights revenues.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 decreased by $75$200 million in the first threesix months of 2011, as compared with the same period of 2010. The following table presents changes from the prior year by expense category:
        
 Increase  Increase 
Expenses — Changes (Decrease) 
Expenses - Changes (Decrease) 
 (In millions)  (In millions) 
Purchased power costs $(71) $(192)
Other operating costs  (31)  (53)
Amortization of regulatory assets, net 23  46 
General taxes 4 
Provision for depreciation  (1)
      
Net Decrease in Expenses
 $(75) $(200)
      
Purchased power costs decreased $71by $192 million in the first threesix months of 2011, compared to the same period of 2010, primarily due to decreased KWH purchased to source generation sales requirements. Other operating costs decreased $31by $53 million in the first threesix months of 2011, primarily due to lower transmission congestion and transmission loss expenses that are now included in the cost of purchased power (see reference to deferral accounting above). The amortization of net regulatory assets increased $23by $46 million in the first threesix months of 2011, primarily due to reduced NUG deferrals as a result of a PPUC approved increase in Penelec’s NUG Rider implementedcost recovery rider in January 2011. General taxes increased $4 million primarily due to higher Pennsylvania Sales and Use Taxes and the absence of a favorable ruling on a property tax appeal in the first quarter of 2010.

 

131145

ITEM 3. 
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Risk Information” in Item 2 above.
ITEM 4. 
CONTROLS AND PROCEDURES
(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES — FIRSTENERGY
FirstEnergy’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 CONTROL OVER FINANCIAL REPORTING
During the quarter ended March 31,June 30, 2011, other than changes resulting from the Allegheny merger discussed below, there have been no changes in internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, FirstEnergy’s, FES’, OE’s, CEI’s, TE’s, JCP&L’s, Met-Ed’s and Penelec’s internal control over financial reporting.
On February 25, 2011, the merger between FirstEnergy and Allegheny closed. FirstEnergy is currently in the process of integrating Allegheny’s operations, processes, and internal controls. See Note 2 to the consolidated financial statements in Part I, Item I for additional information relating to the merger.

 

132146

PART II. OTHER INFORMATION
ITEM 1. 
LEGAL PROCEEDINGS
ICG Litigation
On December 28, 2006, AE Supply and MP filed a complaint in the Court of Common Pleas of Allegheny County, Pennsylvania against International Coal Group, Inc. (ICG), Anker West Virginia Mining Company, Inc. (Anker WV), and Anker Coal Group, Inc. (Anker Coal). Anker WV, now known as Wolf Mining Company, entered into a long term Coal Sales Agreement with AE Supply and MP for the supply of coal to the Harrison generating facility. Anker Coal, now known as Hunter Ridge Holdings Inc., guaranteed performance under the contract. Prior to the time of trial, ICG was dismissed as a defendant by the Court, which issue can be the subject of a future appeal. As a result of defendants’ past and continued failure to supply the contracted coal, AE Supply and MP have incurred and will continue to incur significant additional costs for purchasing replacement coal. A non-jury trial was held on January 10, 2011 through February 1, 2011. At trial, AE Supply and MP presented evidence that they have incurred damages for replacement coal purchased through the end of 2010 and will incur additional damages for future shortfalls. The total damages claimed were in excess of $150 million. Defendants primarily claim that their performance is excused under a force majeure clause in the coal sales agreement and presented evidence at trial that they will continue to not provide the contracted yearly tonnage amounts. On May 2, 2011, the court entered a verdict in favor of AE Supply and MP for $104 million, which may be challenged in post-trial filings and an appeal.
Additional Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 109 and 1110 of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
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, 2010, includes a detailed discussion of its risk factors. In connection with the recent acquisition of Allegheny and the current events in Japan, the information presented below updates and supplements theas modified by changes to certain risk factors appearingdisclosed in our annualQuarterly Report on Form 10-K10-Q for the yearperiod ended DecemberMarch 31, 2010.
Potential NRC Regulation in Response to the Incident at Japan’s Fukushima Daiichi Nuclear Plant
As a result of the NRC’s investigation of the incident at the Fukushima Daiichi nuclear plant, potential exists for the NRC to promulgate new or revised requirements with respect to nuclear plants located in the United States, which could necessitate additional expenditures at our nuclear plants. It is also possible that the NRC could suspend or otherwise delay pending nuclear relicensing proceedings, including the Davis-Besse relicensing proceeding. FirstEnergy cannot currently estimate the impact of any such regulatory actions on its financial condition or results of operations.
Risks Associated With Our Recently Completed Merger
Our Merger with AE May Not Achieve Its Intended Results.
We entered into the merger agreement with AE with the expectation that the merger would result in various benefits, including, among other things, cost savings and operating efficiencies relating to the regulated segments and the unregulated competitive segment. Our ability to achieve the anticipated benefits of the merger is subject to a number of uncertainties, including whether the business of Allegheny is integrated in an efficient and effective manner and maintenance of the current credit ratings of the combined company and its subsidiaries. Failure to achieve these anticipated benefits could result in increased costs, decreases in the amount of expected revenues generated by the combined company and diversion of management’s time and energy and could have an adverse effect on the combined company’s business, financial results and prospects.
As a Result of the Merger We Will be Subject to Business Uncertainties That Could Adversely Affect Our Financial Results.
Although we are taking steps designed to reduce any adverse effects, uncertainty about the effect of the merger with AE on employees and customers may have an adverse effect on us. Employee retention and recruitment may be particularly challenging, as employees and prospective employees may experience uncertainty about their future roles with the combined company. Despite our retention and recruiting efforts, key employees may depart or fail to accept employment with us because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company. Additionally, customers, suppliers and others that deal with us may seek to change existing relationships.
Furthermore, the integration of Allegheny into our company may place a significant burden on management and internal resources. The diversion of management attention away from day-to-day business concerns and any difficulties encountered in the transition and integration process could affect our financial results. In each case, our business results could be affected.

133

The Combined Company Will Have a Higher Percentage of Coal-Fired Generation Capacity Compared to FirstEnergy’s Previous Generation Mix. As a Result, FirstEnergy May Be Exposed to Greater Risk from Regulations of Coal and Coal Combustion By-Products Than it Faced Prior to the Merger
The combined company’s generation fleet has a higher percentage of coal-fired generation capacity compared to FirstEnergy’s previous generation mix. As a result, FirstEnergy’s exposure to new or changing legislation, regulation or other legal requirements related to greenhouse gas or other emissions may be increased compared to its previous exposure. Approximately 52% of FirstEnergy’s pre-merger generation fleet capacity was coal-fired, with the remainder being low-emitting natural gas, oil fired or non-emitting nuclear and pumped storage. Approximately 78% of Allegheny’s generation fleet capacity is coal-fired. Approximately 62% of the combined company’s fleet capacity is coal-fired. Historically, coal-fired generating plants face greater exposure to the costs of complying with federal, state and local environmental statutes, rules and regulations relating to emissions of substances such as sulfur dioxide, nitrogen oxide and mercury. In addition, there are currently a number of federal, state and international initiatives under consideration to, among other things, require reductions in greenhouse gas emissions from power generation or other facilities and to regulate coal combustion by-products, such as coal ash, as hazardous waste. These legal requirements and initiatives could require substantial additional costs, extensive mitigation efforts and, in the case of greenhouse gas legislation, could raise uncertainty about the future viability of fossil fuels as an energy source for new and existing electric generation facilities. Failure to comply with any such existing or future legal requirements may also result in the assessment of fines and penalties. Significant resources also may be expended to defend against allegations of violations of any such requirements. FirstEnergy expects approximately 70% of its generation fleet to be non-emitting or low-emitting by the end of 2011. All of Allegheny’s supercritical coal-fired generation assets are scrubbed, and its generation portfolio also includes pumped storage and natural gas generation capacity. The combined company’s generation fleet nevertheless could face greater exposure to risks relating to the foregoing legal requirements than FirstEnergy’s pre-merger fleet due to the combined company’s increased percentage of coal-fired generation facilities.
ITEM 2. 
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 firstsecond quarter of 2011.
                                
 Period  Period 
 January February March First Quarter  April May June Second Quarter 
  
Total Number of Shares Purchased(a)
 32,053 543,138 1,344,212 1,919,403  213,550 367,422 428,966 1,009,938 
  
Average Price Paid per Share $38.36 $38.44 $37.55 $37.81  $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 for some or all of the following: 2007 Incentive Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan, Director Compensation, Allegheny Energy, Inc. 1998 Long-Term Incentive Plan, Allegheny Energy, Inc. 2008 Long-Term Incentive Plan, Allegheny Energy, Inc, Non-Employee Director Stock Plan, Allegheny Energy, Inc, amendedAmended and Restated Revised Plan for Deferral of Compensation of Directors, and Stock Investment Plan.

134

ITEM 5. 
OTHER INFORMATION
Signal Peak Mine Safety
FirstEnergy, through its FEV wholly-owned subsidiary, has a 50% interest in Global Mining Group LLC, a joint venture that owns Signal Peak which is a company that constructed and operates the Bull Mountain Mine No. 1 (Mine), an underground coal mine near Roundup, Montana. The operation of the Mine is subject to regulation by the Federal Mine Safety and Health Administration (MSHA) under the Federal Mine Safety and Health Act of 1977 (Mine Act).
Section 1503 of the Dodd-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 extent applicable, disclosing in periodic reports filed under the Securities Exchange Act of 1934 the receipt of certain notifications from the MSHA.

147

On November 19, 2010, Signal Peak received a letter from MSHA placing it on notice that the Mine has a potential pattern of violations of mandatory health or safety standards under Section 104(e) of the Mine Act. If implemented, Section 104(e) requires all subsequent violations designated as Significant and Substantial be issued as closure orders with all persons withdrawn from the affected area except those necessary to correct the violation. On March 16, 2011, Signal Peak Mine received a letter from MSHA indicating that the mine is no longer being considered for a pattern of potential violations notice.
Signal Peak received the following notices of violation and proposed assessments for the Mine under the Mine Act during the three months ended March 31,June 30, 2011:
        
 Signal  Signal 
 Peak  Peak 
Number of significant and substantial violations of mandatory health or safety standards under 104* 22  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) 13  8 
Number of mining related fatalities —  — 
Total dollar value of proposed assessments $1,892  $6,989 
* References to sections under Mine Act
The inclusion of this information in this report 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.

135

ITEM 6. 
EXHIBITS
Exhibit Number
FirstEnergy     
Exhibit Number 
FirstEnergy
 3.1  Amendment 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  Allegheny Energy, Inc. 1998 Long-Term Incentive Plan (incorporated by reference to FirstEnergy’s Form 8-K filed February 25,Credit Agreement, dated as of June 17, 2011, Exhibit 10.2, File No. 21011)among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power Company, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.
     
10.2Allegheny Energy, Inc. 2008 Long-Term Incentive Plan (incorporated by reference to FirstEnergy’s Form 8-K filed February 25, 2011, Exhibit 10.3, File No. 21011)
10.3Allegheny Energy, Inc. Non-Employee Director Stock Plan (incorporated by reference to FirstEnergy’s Form 8-K filed February 25, 2011, Exhibit 10.4, File No. 21011)
10.4Allegheny Energy, Inc. Amended and Restated Revised Plan for Deferral of Compensation of directors (incorporated by reference to FirstEnergy’s Form 8-K filed February 25, 2011, Exhibit 10.5, File No. 21011)
10.5Amendment to FirstEnergy Corp. 2007 Incentive Compensation Plan, effective January 1, 2011
10.6Amendment to FirstEnergy Corp. Executive Deferred Compensation Plan, effective January 1, 2012
10.7Amendment to FirstEnergy Corp. Deferred Compensation Plan for Outside Directors, effective January 1, 2012
10.8Amendment to FirstEnergy Corp. Supplemental Executive Retirement Plan, effective January 1, 2012
10.9FirstEnergy Corp. Change in Control Severance Plan
10.10Amendment to Employment Agreement, dated February 25, 2011, between FirstEnergy Service Company and Gary R. Leidich
 12  Fixed charge ratios
     
 31.1  Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
     
 31.2  Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
     
 32  Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
     
 101* The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the period ended March 31,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.

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.
     
FESOE  
 10.1  Asset PurchaseCredit Agreement, dated as of March 11,June 17, 2011, byamong 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 between FirstEnergy Generation Corp.West Penn Power, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and American Municipal Power, Inc.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)
     
32Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
OE
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
CEI
12Fixed charge ratios
31.1Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
31.2Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
 32  Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
     
 101
TE* 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*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.

 

136149

     
Exhibit Number  
JCP&LTE 
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
Met-Ed* 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
Penelec* 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

150

   
Exhibit Number
101* 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.
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 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 blocks of text and (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.

 

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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
May 3,August 2, 2011
FIRSTENERGY CORP.
Registrant
     
 FIRSTENERGY CORP.
Registrant

FIRSTENERGY SOLUTIONS CORP.

Registrant

OHIO EDISON COMPANY
Registrant

THE CLEVELAND ELECTRIC
ILLUMINATING COMPANY
Registrant

THE TOLEDO EDISON COMPANY
Registrant

METROPOLITAN EDISON COMPANY
Registrant

PENNSYLVANIA ELECTRIC COMPANY
Registrant
 		 
   
Harvey L. Wagner  
 Vice President, Controller
and Chief Accounting Officer 
OHIO EDISONJERSEY CENTRAL POWER & LIGHT COMPANY

Registrant
 		 
   
K. Jon Taylor  
 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
Registrant		Controller
(Principal Accounting Officer) 		 
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)

 

138152